CA2652930A1

CA2652930A1 - In-situ recovery of bitumen or heavy oil by injection of di-methyl ether

Info

Publication number: CA2652930A1
Application number: CA2652930A
Authority: CA
Inventors: Boleslaw L. Ignasiak; Keijiro Yamaoka
Original assignee: Individual
Current assignee: Individual
Priority date: 2009-01-20
Filing date: 2009-01-20
Publication date: 2010-07-20
Anticipated expiration: 2029-01-20
Also published as: CA2652930C

Abstract

A method is provided for energy efficient, environmentally friendly, in-situ recovery of bitumen or heavy oil by injecting di-methyl ether (DME) into the reservoir. The method includes the steps of heating the reservoir utilizing the condensation and latent heats of injected DME liquids and/or vapours, mobilizing the bitumen/heavy oil by lowering its viscosity, dissolving the water and some of the components of the bitumen/heavy oil in the DME, recovering from the reservoir the mixture of bitumen and DME containing the dissolved components of the bitumen, separating the DME from the mixture by depressurization followed by pressurizing, heating and re-injecting the recovered DME, into the reservoir.

Description

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 (DME) into the reservoir using equipment comparable to that applied for steam assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS), recovering the mobilized bitumen/heavy oil from the reservoir, separating the DME from the bitumen/heavy oil by depressurizing followed by pressurizing, heating and re-injecting the recovered DME 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 (SAGD) technology for in-situ recovery of bitumen from Alberta oil sands deposits.
The SAGD 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 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 30- 40 % of the cost of producing I
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 the 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 C02, 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 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) type of technologies. In general VAPEX-type 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 heated to usually less than 100 C. 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, to some extent, from solubilisation of some components of the bitumen in the hydrocarbons. The product composed of bitumen and some components of bitumen dissolved in hydrocarbon-solvent is, after recovery from the production well, subjected to flash distillation; the hydrocarbon vapours are recovered, pressurized, heated 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 injection and product collection pipes. 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 deasphalting. For this purpose the N-Solv Process (1) applies propane, a well known deasphalting agent, as a hydrocarbon for in-situ recovery of bitumen.

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. Typically 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

2 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 solvent losses - so far the field trials show losses in the range of 10-25%; the need for using high purity solvents -especially N-Solv Process;
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 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 hot, 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 heats of the DME and the capacity of DME to act as a solvent, draining the product composed of liquid bitumen, DME
containing dissolved components of bitumen and water towards the product collection pipe, accumulating the product in the collection pipe, delivering the product to the surface via the production well, subjecting the product to flash distillation by depressurizing, separating the DME vapours, pressurizing and heating the separated vapours and recycling the DME liquids and/or vapours into the process, cleaning, pipelining and utilizing the bitumen as required.

The present invention, as summarized above and compared to prior art replaces costly and scarce hydrocarbons with DME, requires less energy for pressurizing/heating and recycling the DME compared to most preferred hydrocarbon solvents, effectively removes water from the gravity drainage chamber by solubilisation in DME, enhances the mobilization of bitumen by dissolving the water, the polar and other components of the bitumen and, therefore, increasing the porosity of the oil sands ore and the rate of penetration of DME vapours into the pre-dried ore, reduces the viscosity of the generated DME/bitumen binary liquid compared to propane/bitumen liquid, uses DME solvent costing less compared to liquefied petroleum gas (LPG) or condensate from which the hydrocarbon solvents have to be separated, uses non-hydrocarbon solvent that can be readily manufactured, is widely accessible, environmentally benign and decomposes over relatively short period of time when released to atmosphere.

3 .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-CO2 drive two-stroke Diesel engine co-generation system with re-burning 02-CO2 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.

Description 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 synthesis gas 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 (50-55) compared to quality hydrocarbon based Diesel oil (45-50). 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. Specifically, DME does not contain any sulphur or nitrogen and, therefore, the products of DME combustion in nitrogen free atmosphere are essentially free of any sulphur and nitrogen oxides (SOx and NOx). 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 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 do not appear to be significant. The major difference that results from structural make-up of both solvents (ether versus hydrocarbon) is the capability of DME to dissolve water and some polar compounds. Propane does not show any capability for water dissolution. Furthermore, propane, butanes and pentanes, have been well known for their capabilities to precipitate some polar compounds from bitumen solutions

4 and are applied as deasphalting agents. The capability of DME to dissolve water and polar compounds indicates that injecting DME into the gravity drainage chamber shall preferentially remove water and some polar compounds from the oil sands ore. Dissolution of both, water and some polar compounds should increase the porosity of the oil sands ore, make it more accessible to DME vapours, facilitate the heat transfer and mobilization of the bitumen and reduce the viscosity of the binary liquid composed of the bitumen and its components dissolved in DME.

The important advantage of the present invention is that DME required for in-situ bitumen recovery can be generated from non-petroleum, solid fossil fuels (2, 3). There is a consensus among DME producers that subject to availability of low cost solid fossil fuel DME is very competitive, in terms of price, compared to Diesel fuel, liquefied petroleum gas (LPG) and condensate. Propane recommended by prior art for in-situ recovery would have to be separated from either LPG or condensate or both. Since, according to prior art (1), high purity, methane free propane is required, the cost of propane separation would further increase the cost of clean propane. Both LPG and condensate are products of natural gas processing.
Limited availability of LPG and condensate in Northern Alberta is of considerable concern to the oil sands industry and impedes its growth. Increasing shortage of condensate required for bitumen pipelining makes condensate an unlikely starting material for production of huge quantities of propane required for in-situ bitumen recovery. Propane losses encountered during bitumen recovery may amount to 10-25 %.

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 compounds namely, asphaltenes, some resins and some high molecular weight aromatics.
Using any of the existing deasphalting procedures the asphaltenic fraction can be effectively separated from the DME recovered bitumen and subjected to co-processing (4) yielding distillable oils in quantities essentially equivalent to the mass of the separated asphaltenic fraction. The deasphalted 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 coke. 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 about 30-40 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 effective deasphalting process prior to upgrading, will generate coke and impede the upgrading process.
Therefore, the propane assisted bitumen recovery generates product that will still require deasphalting. The hydrogen rich (-8.5 wt% H) asphaltenes left in the reservoir when propane is used for bitumen recovery are irreversibly lost and cannot be utilized for generation of distillable oils (4) 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 (see propane critical temp., Table 1). By contrast, DME can effectively transfer the heat of condensation at temperatures up to 1 270C.

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 electric power and heat generation. Such utilization of DME will eliminate the need for pipelining natural gas that is required for SAGD as well as for hydrocarbon based bitumen recovery. Two-stroke DME fired Diesel engines utilizing oxygen and capable of recycling the flue gas to increase the thermal efficiency and separation of CO2 will generate, in addition to electric power, enough heat to separate DME from the bitumen. Furthermore, two-stroke Diesel engines are expected to simplify the operation of the in-situ bitumen recovery plant and lower its capital cost.

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 50 C
and pressures over 1 MPa the viscosity of the blend composed of 75% bitumen and 25% DME
would be less than 7 cSt. Increasing the content of DME in the blend to 30%
would reduce the viscosity to below 3 cSt. Reducing the content of DME in the blend to 20%
would result in viscosity of about 12 cST or less. It is, therefore, expected that removal of blends composed of 80-85% of bitumen and 20-15% DME from the gravity drainage chamber operating at depth over 130 m, temperatures over 50 C 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. 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 0-40 C bitumen/DME blend containing 15-20 wt% DME would satisfy this requirement. The pressure generated by saturated DME vapours at temperatures up to 40 C
will be below 0.9 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
does not precipitate any components of bitumen, as C3-C5 (propane, butanes, pentanes) hydrocarbons do. Precipitation increases the pressure drop thus reducing the 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, butane and DME could be carried out, due to low pressure of saturated vapours of these compounds, at depth less than 130 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 carried out at depth as low as 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.
It therefore appears that as compared with the most promising hydrocarbons, DME has significant advantage for in-situ recovery of bitumen from oil sands ores that cannot be recovered by mining.

The most 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 and that 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. Consequently, 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 O2/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. The CO2 emissions from a central power plant would be about 5-10%
only compared to emissions from a SAGD plant and about twice less compared to propane based in-situ bitumen recovery plant. The capture and sequestration of CO2 emissions generated by the facility as presented in Fig. 4 would not present any major technical challenge. On the other hand 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
prior to its injection 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 oil pipes/pipelines to temperatures as high as160 C. 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
(by pipelines) and electric power (by transmission lines) only. Under such circumstances there would be no need to locate the power and heat co-generation plant in a central location in the Athabasca 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 facility located in Edmonton area. The heat generated by co-generation plant would be fully utilized by the integrated facility and specifically, by the co-processing plant.
The DME based in-situ bitumen recovery plants located in Athabasca region would pipeline the binary liquids, freed of particulates and non- condensable gases, directly to integrated facility in Edmonton area for separation, 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 .cease to emit any CO2 and/or volatile organic hydrocarbons (VOC's); 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, separation and disposal of C02-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 1:

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 (CH2CI2) 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 solid CO2 and vented to atmosphere.

The experiment was carried out as follows. About 1,000 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 (CH2CI2). 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 CH2CI2 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.

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 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%.

References (1) Press Release, Calgary AB, November 20, 2006, Enbridge and Hatch Invest in N-Solt' 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., Japan, October 2005 (4) Canadian Patent Application No. 2,604,058, Ignasiak B. L. Applicant &
Inventor, Filing Date 2007, 10, 05

Claims

1. A method for in-situ recovery of bitumen or heavy oil from their reservoirs by application of di-methyl ether (DME), comprising the steps of:

a) heating the pressurized DME in the form of hot liquid and/or vapours, or a mixture of hot vapours and liquid;
b) injecting the hot DME in the form of hot liquid and/or hot vapours into the gravity drainage chamber of a reservoir containing oil sands ore or heavy oil using the same equipment as applied for steam assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS);
c) heating the oil sands ore or heavy oil contained in the gravity drainage chamber by utilizing the condensation and/or latent heat of the DME liquid and/or vapours;
dissolving the water, some polar and other soluble components of the bitumen/heavy oil in the liquid DME thus forming DME solute; lowering the viscosity of the bitumen/heavy oil and forming binary liquid composed of the bitumen and the DME
solute;
d) utilizing the downward flow of the binary liquid to collect it in the product collection pipe; recover the binary liquid through the product well;
e) pipeline the binary liquid to bitumen processing/upgrading plant, heat and depressurize the binary liquid and recover the DME vapours from the binary liquid by flash distillation, pressurize recovered DME vapours together with the make-up DME
and pipeline the DME back to the in-situ bitumen recovery plant for heating and re-injecting into the gravity drainage chamber.

2. A method according to claim 1, wherein the power required by DME based plant for in-situ recovery of bitumen or heavy oil is supplied by DME fired O2/CO2 drive two-stroke Diesel co-generation engine with DME re-burning O2/CO2 drive boiler and cryogenic CO2 capture system.

3. A method according to claim 1, wherein the heat required by DME based in-situ bitumen or heavy oil recovery plant for raising the temperature of the pressurized DME
prior to injecting it into the bitumen or heavy oil reservoir is provided by application of Skin Electric Current Tracing (SECT) method.

4. A method according to claim 1, step a), wherein the pressure applied to DME
is in the range of 0.5 to 5.4 MPa and the temperature of DME is in the range of 20-127°C.

5. A method according to claim 1, step a), wherein the hot and pressurized DME
occurs in the form of liquid only, or vapour only, or any mixture of liquid and vapour.

6. A method according to claim 1, step b), wherein any additives, surfactants and collectors or a mixture of additives, surfactants and collectors is admixed with the DME to be injected into the reservoir.

7. A method according to claim 1, step b), wherein in addition to SAGD and CSS
equipment any other equipment suitable for injecting DME hot liquid or vapours or a mixture of DME hot vapours and liquid into the gravity drainage chamber can be applied.

8. A method according to claim 1, step c), wherein any number of adjacent gravity drainage chambers is heated using DME hot liquids and/or vapours.

9. A method according to claim 1, step d), wherein in addition to SAGD and CSS
equipment any other equipment suitable for DME based binary liquid collection and recovery can be applied.

10. A method according to claim 1, step d), wherein the binary liquid recovered from the production well contains up to 40% DME.

11. A method according to claim 10, wherein the content of DME in the binary liquid recovered from the production well can be adjusted to between 15-20%.

12. A method according to claim 1, step e), wherein the binary liquid recovered from the production well is depressurized on-site and the recovered DME vapours are pressurized, subjected to heating according to claim 3 and re-injected into the reservoir.