CA3122517A1 - Advanced/integrated dme-based technology for in-situ bitumen extraction, partial upgrading and hydrogen/power generation - Google Patents

Abstract

A sustainable technology is provided for Dimethyl Ether (DME)-based in-situ recovery and partial upgrading of bitumen and generation of hydrogen; the bitumen recovery includes the steps of in-reservoir electric heating, transporting the generated bitumen/DME dilbit to integrated central facility (ICF); processing the dilbit and partial upgrading of the bitumen, if required;
generating the DME and electric power in the ICF; recycling, utilizing and upgrading any by-products with emphasis on CO2, ensuring that the ICF does not produce any non-salable by-products; reducing the production costs of DME, electric power and other generated value-added products by optimizing the integration of the unit processes employed within the ICF, utilizing the infrastructure developed for liquefied petroleum gas (LPG) and liquefied natural gas (LNG) to handle, store, pipeline and ship the DME and/or bitumen/DME dilbit to customers interested in employing DME and bitumen as quality Diesel or cooking fuel or feedstock for petrochemicals or asphalt; converting on customer's site the delivered DME by hydrolysis/steam reforming into hydrogen; separating the impurities from the hydrogen if require, generating a product that meets the requirements for powering fuel cells; converting the energy contained in the hydrogen into electric power and mechanical energy to replace hydrogen and batteries for powering transportation vehicles.

Description

DESCRIPTION
The present invention is directed towards the in-situ recovery of bitumen, partial upgrading if required, and generation of hydrogen based on application of Dimethyl Ether (DME). The bitumen recovery plants are supplied with liquefied DME and electric power by integrated central facility (ICF). Alternatively, the power is generated directly at bitumen recovery site by diluting DME with water thus forming DME/water blends that are converted into hydrogen and electricity using portable or stationary systems for blends hydrolysis/reforming, removing impurities from hydrogen-rich gas, if required, and feeding pure hydrogen into fuel cells to generate electricity at near 90% thermal efficiency. The ICF produces DME either by dehydration of methanol generated by catalytic photosynthesis of CO2/H20 blend or from a syngas produced by tri-reforming of blends of volatile gases containing CO2 or by reforming natural gas (CH4) using equimolecular volumes of CO/H2 (CO/H2=1/1 vol. ratio) or from co-gasification or other commercially applied processes for generation of syngas to be utilized for DME
synthesis. The CO2 is produced within the ICF from syngas as a by-product of either direct DME
synthesis or by co-gasification of blends composed of subbituminous and low-rank bituminous coals and heavy bottoms/residues produced by bitumen distillation followed by separating the CO2 generated by individual unit processes at ICF site; the ICF will accept CO2 supplied by off-site emitters based on terms and conditions of carbon tax and/or cap-and-trade regulations and fee-for-service agreements. By recycling and utilizing the on-site and off-site generated CO2 for DME synthesis the ICF facility will generate significant revenue; the bitumen/extra heavy oil recovery will be converted into a highly profitable technology. The revenue generated shall suffice to either significantly reduce or eliminate the cost of DME production thus further lowering the cost of bitumen recovery and/or hydrogen generation. The low-cost or a cost-free DME can be handled, stored and pipelined/shipped using the same infrastructure as that developed for the LPG
or LNG and delivered to any destination. At the destination site the DME will be blended with water and the blend will be subjected under very mild conditions to hydrolysis/reforming with steam to generate gaseous product containing approximately +70vo1.% hydrogen in addition to CO2 and minute quantities of CO. The latter carbon-containing gases can be removed by commercial separation technologies, if required, thus generating nearly pure hydrogen. The hydrogen can be utilized for a variety of applications including generating the electricity powering fuel cells.
Background of the Invention Field of the Invention: Canadian ultimate in-place bitumen reserves amount to approximately 2.2 trillion barrels and account presently for nearly 70% of total world's petroleum reserves. The Steam Assisted Gravity Drainage (SAGD) has been commercially employed in Alberta for bitumen recovery for over two decades. SAGD recovers on average 50% bitumen from the "best of the best reservoirs". These reservoirs contain approximately 170 billion barrels of bitumen from which SAGD shall be able to recover about 85 billion barrels - that amounts to less than 4% of the ultimate in-place Alberta's bitumen reserves. Rystad Energy Research estimated the cost of bitumen recovery by SAGD and upgrading to distillate at US$76/barrel (C$98-100/barrel; 2019 US$) ¨ one of the world's costliest for petroleum liquids production. Oil sands plants' CO2 emissions account for nearly 8% of total CO2 emitted in Canada according to industry data. The data accumulated by independent sources indicate that these emissions are likely 60-70% higher. The bitumen recovery (SAGD) plants require around 3 volumes of water per 1 volume of bitumen generated. At such huge CO2 emissions and demand for water further expansion of Alberta bitumen production using SAGD is not feasible, especially in view of ever increasing world-wide environmental concerns. The water has to be converted to high temperature steam (200-230 C) prior to injection into the reservoir. The heat from natural gas combustion is employed for steam generation.
The cost of natural gas for steaming typically amounts to approximately 27% of SAGD's operating cost.
The process water has to be treated prior to recycling, the make-up (potable) water accounts for up to 20% of the recycled water. Furthermore, as opposed to conventional crudes that typically are nearly 100% distillable, about 50% of recovered bitumen is non-distillable and requires special processing.
Description of prior art: "The best of the best" deposits have been already exploited using SAGD. Huge efforts have been placed into SAGD's improvement but the results are not encouraging. Over the last twenty years SAGD's average overall bitumen recovery has been essentially the same. It is expected that the recoveries from the remaining not "the best of the best" reservoirs will be reduced with time thus resulting in further increases in bitumen recovery costs.
Growing world's attention to climate change leads to the conclusion that if Canada is to benefit from the immense bitumen reserves, SAGD has to be replaced with a significantly more effective technology [1].
Since 2014 the poor performance of SAGD has been the key factor in the near collapse of Alberta's and significant damage of Canadian economies. The economic collapse resulted in loss of hundreds of thousands of jobs in Alberta and Canada and has been deepen by:
= crude oil price wars/volatility, = a dramatic drop in crude oil consumption precipitated by COVID-19, = the blacklisting of the four largest Alberta bitumen producers by Equinor - the biggest world's energy fund, = the long standing commitment made by the federal government of Canada to G20 to eliminate by 2025 the subsidy of $3 billion/year to Alberta bitumen industry, and, = Keystone XL pipeline cancellation by the United States President.
SAGD does not meet the environmental and economic standards of the 21 century technology for fossil fuels processing and utilization. That threatens the very existence of the Alberta bitumen industry.
The crude oils markets volatility is one of the major factors preventing SAGD's continued application.
The experts acknowledge that the prognoses regarding markets volatility are unreliable and present huge problems to producers of crude oils of which the production costs are very high; that includes bitumen and extra heavy crudes in particular. But the experts do agree that ultimately, over a long run "the low-cost producers will win". The DME-based technology enables the bitumen recovery ¨ the uniquely Canadian industry - to become a low-cost energy source and ensure that the technology will make a contribution to reversing the climate change.
As compared to SAGD the optimal DME bitumen extraction technology has the capacity to:
= Eliminate CO2 emissions and the wasteful unit processes of the SAGD
technology;
= Reduce energy consumption by 10 times;
= Nearly double bitumen recovery;

2 = Increase bitumen recovery rates by 3-4 times;
= Reduce bitumen recovery capital and operating costs by 80% and +80%, respectively.
The DME technologies can be implemented in a step-wise manner. The first step to implement DME
technology is to demonstrate the DME-assisted SAGD. Based on the knowledge acquired so far this step is essentially capital cost- and risk-free and is expected to provide the answers as to how the integration of the individual unit processes can be carried out to optimize the technology in terms of economic and environmental performance.
Summary The present invention is based on application of DME for both, the in-situ extracting of bitumen/extra heavy oil and producing +99vo1.% pure hydrogen by hydrolysis/reforming of DME.
DME appears to be an excellent solvent for extracting the bitumen/extra heavy oil. It is also very promising as hydrogen donor. The economics of bitumen and hydrogen production using DME will be further improved by reducing the production cost of DME.
DME has the capability to generate hydrogen under very mild hydrolysis/reforming conditions (atmospheric pressure; temperature of +200 C).
DME production cost by direct synthesis from syngas is very reasonable (US$ 60-90/ton; 2007 US$) and could be further reduced by recycling the CO2, the major by-product of DME
direct synthesis and utilizing CO2 to reduce the demand for natural gas to produce DME. A major progress has been made in this area during the last two decades.
The utilization of CO2 emissions for DME production will generate additional cash flow to ICF operators and release them from paying GHG emission penalties. The penalties will gradually increase by C$15 every year to amount to C$170/tonne-0O2 commencing in 2030. Recycling CO2 and its utilization for DME production will significantly reduce the cost of DME synthesis and electric power generation.
Maximal reduction of DME production cost is essential to optimize the in-situ bitumen recovery and the cost of hydrogen generation from DME. It is also the key to successful transition from today's SAGD
bitumen recovery to highly profitable DME-based extraction during approximately the next 2-5 years.
Down the road this process will facilitate the transformation of the bitumen-based energy industry into economically and environmentally most effective hydrogen-based energy economy.
DME can be stored, handled, pipelined and shipped using the same infrastructure that has been developed for carbon based LPG and LNG. By maximally reducing DME production cost Canada shall become a major producer of DME. Since no infrastructure has been developed for effective handling and shipping the hydrogen in particular, Western Canada, by developing an advanced expertise in DME
production shall emerge as a major exporter of DME. DME could be readily converted to hydrogen at any site selected by the overseas customer(s).
Brief Description of the Tables and Drawing Table 1 presents the assumptions for GHG emission estimates for SAGD's baseline conditions versus DME project conditions. It has been assumed that both facilities, SAGD and DME, have the same annual

3 output of 300,000 bpd bitumen at 100% availability. Energy provision for SAGD
facility is based on natural gas combustion.
Table 2 presents the results of GHG emission estimates for both, SAGD and DME
bitumen recovery facilities. The results show that SAGD facility will generate approximately 0.132 metric tons-0O2/barrel bitumen; the DME facility will generate approximately 0.021 metric tons-0O2/barrel bitumen. Therefore, replacing SAGD with DME plant will result in reducing CO2 emissions by approximately 85%. The balance of pure CO2 (15%) is collected in a liquid form; this CO2 will be utilized and not emitted to atmosphere.
For DME facility the calculations were done based on assumption that the reservoir would be heated by immersion heaters from 10 to 80 C. As of now the indications are that the final temperature of around 50 C will suffice to achieve high recovery rates for DME plant. Therefore, it can be expected that the DME plant, as compared to SAGD plant, will reduce CO2 emissions by more than 85% and further reduce energy consumption.
Table 3 summarizes the information on the basic (1), advanced (2) and optimal (3) DME technologies for in-situ recovery of bitumen from the reservoir. It outlines the key features of the technologies, major changes in plant operation depending upon the technology selected and expected performance of the technology.
Fig. 1 is a flow diagram of the conventional SAGD plant. The plant requires huge volumes of water that is converted into high temperature (200-230 C) steam using the heat from natural gas combustion. The objective of the steaming is to raise the temperature of the bitumen to the range of 80-100 C to make the bitumen recoverable by pumping. The SAGD plant typically requires 10 (ten) times more energy and its mass flow of recycle fluids (steam/water) is about 30 times higher as compared to DME plant with same bitumen output.
Fig. 2 is a flow diagram of an advanced DME plant that is supplied with liquid DME and electric power from the Integrated Central Facility (ICF). The DME plant eliminates combustion of natural gas, CO2 emissions, a need for recycled water treatment and process water disposal. In-reservoir electric heating is applied. The operational temperature of around 50 C will be sufficient to produce bitumen/DME dilbit.
The generated dilbit can be transported directly to the customer. The DME
plant will produce small volumes of reservoir water that will meet the requirements for surface disposal.
1.0 Description of the Preferred Embodiments: Recovery of Bitumen/Heavy Oil from their Reservoirs by DME-Based Extraction 1.1 DME-based bitumen recovery technologies The no-risk improvement of conventional SAGD or the "Hydrocarbons-assisted SAGD" can be achieved by admixing small amounts of DME or other amphoteric solvents to SAGD's steam or replacing hydrocarbons with DME in the "Hydrocarbons-assisted SAGD". The Alberta bitumen industry has been well acquainted with SAGD and the "Hydrocarbons-assisted SAGD". The "DME-assisted SAGD" (the basic version of the DME technology) will utilize the industry's huge multi-billion capital investment into existing SAGD plants. As compared to SAGD the "DME-assisted SAGD" plants [2]
are expected to increase bitumen overall recovery by around 40%, the rate of recovery by up to 100%, reduce CO2 emissions by

4 around 80% and lower the operating cost by +50%. The detrimental environmental impact of SAGD will be significantly reduced. The recovered bitumen containing around 15wt% DME
spiked with methanol will make the blend amenable to pipelining; the need for the condensate is expected to be eliminated.
That will further reduce the cost of bitumen production and lower the transportation cost of bitumen/DME dilbit by approximately US$C20 per barrel of bitumen [3].
DME is one of the safest solvents available [4], it has amphoteric properties (soluble in water and organic compounds) and can be produced commercially at a cost lower compared recovery of light hydrocarbons as practiced by the industry. DME serves as a valuable substitute for LPG
(China) and super-clean Diesel fuel (China & Japan).
Replacing the "DME-assisted SAGD" with the "DME-based Extraction" (the advanced version of the DME
technology) will further elevate the performance of the DME-based technology.
As compared to SAGD
the capital and operating costs of the "DME-based Extraction" plant shall be reduced by up to 80% and +80%, respectively. The DME plant will not require natural gas combustion, supply of water, water steaming, treatment of the recycled water, process water disposal and will not generate GHG emissions.
DME will be supplied by the ICF. If required, the electric power can be also supplied by ICF. As compared to SAGD the consumption of energy will be reduced by around 90%, the bitumen recovery rate increased by up to 4 times.
Replacing the "DME-based Extraction" with the "Integrated DME-based Extraction" requires optimal integration of the ICF. The already constructed "DME-based Extraction" plants will not require any modifications.
The ICF can further reduce operating cost by recycling and converting all generated by-products, including CO2, to value added saleable products. About 90% of the unit processes to be utilized at the ICF have been proven either in commercial or a large demonstration scale. The ICF has, theoretically, the capacity to recycle and convert all generated CO2 into DME thus either reducing by at least 33% or eliminating the demand for natural gas. By accepting CO2 from other off-site sources based on "fee for service" agreements the bitumen producer will generate large flow of cash that will reduce or eliminate DME production cost or generate additional revenue. The produced DME can be utilized for low-cost and carbon-free electric power generation as well as for sale of DME to customers interested in its application as super-clean Diesel fuel or for hydrogen generation (chapter 2.0).
1.2 Bitumen recovery mechanism: SAGD versus DME
SAGD employs steam preheated to 200-230 C for heating the reservoir to reduce the viscosity of bitumen so it can be pumped to the surface. Steam is dispersed within the reservoir primarily via channels and fissures that display the least resistance to flow. Reservoirs containing excessive water are not suitable for bitumen recovery by SAGD ¨ huge volumes of steam are wasted to heat water instead of bitumen. Steam is typically unable to penetrate through those areas of the reservoir that are filled with wet fines and clays bound by bitumen. Typically the bitumen from such areas is non-recoverable.
Bitumen's heterogeneity changes from reservoir to reservoir and can be significant. High molecular weight components of bitumen require, as a rule, more heat for viscosity reduction. Commercial application of SAGD has demonstrated that average overall bitumen recovery is approximately 50% only.
Despite the efforts placed into SAGD's improvement the overall recovery and other parameters of SAGD's performance have remained essentially unchanged. That indicates that SAGD's recovery mechanism based on application of steam is incapable of effectively transferring its heat to the reservoir's bitumen. The fact that SAGD requires 10 times more energy as compared to DME-only extraction unambiguously confirms SAGD's inability to utilize the energy effectively; it also demonstrates that steaming is the main cause of SAGD's economic and environmental underperformance. Replacing the source of heating (combustion of natural gas) is not expected to improve the recovery of bitumen as long as steam is employed for distribution of heat within the reservoir.
The concept of using solvents for bitumen recovery is an old one. The major obstacle to bitumen extraction using solvents has been bitumen industry preference to work with hydrocarbons and ignore a mphoteric solvents. Hydrocarbons are insoluble or only slightly (some low-MW
aromatic hydrocarbons) soluble in water; their density is significantly below that of water and their affinities to bitumen, as determined by specific physical and chemical properties [5], are typically incompatible. These three factors are the main reason why the extensively tested by bitumen producers "Hydrocarbons-assisted SAGD" technology has marginal impact on SAGD's performance. But replacing hydrocarbons with DME
leads to the "DME-assisted SAGD" technology that will significantly outperform the "Hydrocarbons-assisted SAGD" as well as SAGD.
As opposed to hydrocarbons the DME is well soluble in water and a variety of organic compounds, bitumen and heavy oils in particular. Some DME introduced with SAGD's steam to the reservoir will readily dissolve in cold reservoir's water and penetrate in this form, via the water phase, through the ore. The remaining in-reservoir preheated DME will be dispersed in the ore.
Because of its exceptional affinity to bitumen the DME will quickly diffuse into bitumen. The kinetics of DME diffusion will accelerate with an increase in temperature. By the time the temperature is elevated from 10 C to about 50 C (electric in-reservoir heating) the bitumen/DME solution can be readily pumped to the surface. Low boiling hydrocarbons (C3 & C4) have the capacity to rapidly precipitate, even at very low concentrations, the heavy components of bitumen thus hampering product recovery from the reservoir [6]. DME content in the bitumen/DM E solution would have to amount to nearly 90% to reach the onset of precipitation.
DME shall be successfully employed for bitumen recovery from very heterogenic as well as shallow reservoirs due to low vapor pressures at temperatures not exceeding 50 C.
Compared to DME, the application of heavier hydrocarbons (aliphatic over C5 or aromatic) will be costly, require high pressures and temperatures and their insolubility or very low solubility in water and the tendency to collect at the top of water layers as well as the poor affinity of low molecular weight aliphatic hydrocarbons to bitumen will prevent them from extracting the bitumen effectively.
1.3 GHG emissions: SAGD versus "DME-based Extraction"
Tables 1 & 2 relate to GHG emissions from two bitumen recovery facilities of which each is composed of either SAGD or "DME-based Extraction" plants. The number of bitumen recovery plants in each facility is the same and it has been assumed that each facility annual output amounts to 109.5 million barrels of bitumen. Based on the assumptions presented in Table 1, Table 2 presents the GHG emission estimates for both facilities. The results indicate that whilst the SAGD facility will generate 14.5 million metric tons CO2/year, the "DME-based Extraction" is expected to produce 2.4 million metric tons CO2/year; nearly 85% less compared to SAGD's facility. The 2.4 million metric tons are collected as condensed nearly pure CO2 and can be utilized for a variety of applications (see chapter 1.4).
The estimates in Table 2 are based on assumption that the bitumen recovery rates for SAGD and the "DME-based Extraction" technologies will be comparable and the plants will be operational for 12 (twelve) years.
Bench scale testing carried out during 2015-17 by Alberta Innovates [7]
confirmed the claims made in 2007-8 METI proposals to Alberta government that the "DME-based Extraction"
rates are by far higher compared to those of light hydrocarbons. By accepting that the recovery rates of the "DME-based Extraction" are four times those of SAGD, the annual production of bitumen from "DME-based Extraction" would amount to 400% of that of the SAGD plant [8].
Consumption of energy and generation of CO2 by SAGD plant is about 10 and 6-7 times higher, respectively, as compared to "DME-based Extraction".
SAGD plant consumes huge amount of energy to heat the reservoir to 80-100 C.
Delivering this energy requires recycling large volumes of steam and water in order to recover small volume of bitumen. The mass flow of recycled steam/water in SAGD is typically 30 times higher as compared to the mass flow of DME through the "DME-based Extraction" plant. The "DME-based Extraction" plant will pump to the surface huge volumes of bitumen dissolved in small volumes of DME. But the kinematic viscosity of the bitumen/DME dilbit will be significantly lower as compared to that of bitumen generated by SAGD plant.
Small volumes of reservoir's water meeting the conditions for surface disposal will be also pumped to the surface. The mass flow of DME delivered from the surface for bitumen dissolution will be equivalent to around 15wt.% of the bitumen mass recovered from the reservoir. It is expected that unlike the bitumen produced by SAGD, the bitumen/DME dilbit will be freed from water and solids and can be pipelined and shipped directly to a required destination.
1.4 Converting the "DME-based Extraction" into "Integrated DME-based Extraction" technology Such conversion can be attained by several means and includes the options listed below (see the bullets).
These options enable recycling/utilizing CO2 generated within the ICF by DME
synthesis, DME oxy-firing and other unit processes. Recycling/utilizing CO2 is the key to integrating the DME-based bitumen and hydrogen production technology.
= Generating methanol by catalytic photosynthesis of a blend of CO2/H20=1/2 (volume ratio) or heterogeneous catalytic hydrogenation of CO2/H2=1/3 (vol. ratio) blend followed by methanol's dehydration to DME, = Generating DME by Japanese direct synthesis of CO/H2=1/1 (vol. ratio) syngas followed by recycling the main by-product CO2 for methane reforming, = Tr-reforming of blends composed of natural gas (CH4), CO2 and other oxygen containing gases to syngas followed by methanol synthesis and dehydration to DME, = Reacting CO2 with NH3 formed during co-gasification of blends composed of coal and bitumen distillation residues to generate urea {CO(NH2)2} fertilizer, = Selling generated nearly pure CO2 for enhanced oil recovery (EOR), = Recovering geothermal heat using CO2 for heat recovery to generate electric power.
The first bullet lists the process with a ground-braking potential for DME
generation. The process (equation 1) is based on converting the carbon dioxide blended with water vapors into methanol and oxygen. The process has been discovered in a bench scale experimentation approximately ten years ago in Poland and confirmed recently in the United States [9]. To a significant degree it reflects the photosynthesis reaction occurring in the nature; the reaction is known as "Artificial Lear.
(1) 2CO2 + 4H20 4 2CH3OH + 302 Increasing the kinetics followed by a scale-up of this process could enable conversion of today's numerous fossil fuels-based CO2 emitting energy technologies to sustainable energy generation. That is especially true for DME direct synthesis using the Japanese technology followed by DME usage for production of pure hydrogen for electric power generation and recycling the CO2 to eliminate GHGs emissions (chapter 2.0).
With respect to bitumen recovery by extraction with DME, a successful scale-up of the process summarized in equation (1) shall eliminate the need for natural gas. Recycling and applying CO2 by-product from DME direct synthesis eliminates the problem of CO2 disposal and reduces the demand for natural gas. This process, reaction (1), also generates oxygen that might be utilized for producing electric power by oxy-combustion of a small portion of the synthesized DME as well as in the co-gasification process [1]. Successful scale-up of reaction (1) process would eliminate the need for constructing the ASU (air separation unit) as well as the tri-reforming and auto-thermal reforming facilities. The waste water (e.g. from Edmonton municipality) could be pre-treated by utilizing waste heat and reacted with CO2 leading to production of DME from the no- or low-cost substrates.
Conversion of CO2 supplied by off-site producers into value added products ¨ methanol, oxygen and ME, equations (1, 2 and 3) - based on fee-for-service agreements, would generate additional cash flow and result in recovering the bitumen at rock-bottom breakeven cost.
The second process listed under the first bullet is the extensively researched hydrogenation of CO2 to methanol, equation (2) (2) CO2 + 3H2 4 CH3OH + H20 Though the hydrogenation of CO2 has reached an advanced stage of development it requires further work on improving the performance of the catalyst. The methanol generated by both processes, equations (1) and (2) can be dehydrated in a commercial, low-cost process unit to produce DME
(CH3OCH3) and water as the main by-product, equation (3).
(3) 2CH3OH 4 CH3OCH3+ H20 The second bullet offers a solution, tested in a large scale, for production of DME based on direct Japanese synthesis from the equimolar CO/H2=1/1 (vol. ratio) syngas as shown in equation (4). The main by-product CO2, equation (4), is subjected to methane (natural gas) reforming thus generating additional equimolar blend of CO/H2 syngas, equation (5.0) that is recycled for DME
synthesis, as shown in equation (4).

(4) 3C0 + 3H2 4 CH3OCH3 + CO2 (5.0) CO2 + CH4 4 2C0 + 2H2 The processes presented in equations (4) and (5.0) enable on-site utilization of CO2 and can reduce the demand for natural gas. The effectiveness of natural gas (CH4) reforming with CO2, as presented in equation (5.0), requires confirmation in a commercial scale.
The tri-reforming (TRM) technology (third bullet) has the potential to convert a significant portion of the CO2 generated by oxy-combustion of some of the synthesized DME to produce electric power required for pumping and heating the "DME-based Extraction" bitumen recovery plants.
TRM operates based on principles of commercial methane reforming. TRM replaces two frequently applied processes namely, the dry (02) and the wet steam (H2O) reforming of methane. Instead of feeding the reformer with either CH4/0.502 or CH4/H20 blends, the TRM is fed with blends typically incorporating CH4, 02, CO2, and H20. The feed containing several reactants makes the TRM reactions energetically more efficient and less hazardous compared to wet or dry reforming. The TRM offers additional advantages. It allows to change the ratios of feed components, does not require pure CO2, either the flue gas or coke oven gas are acceptable, the catalyst life-time is significantly extended (no carbon deposition), the molecular ratio of CO/H2 in the syngas produced can be adjusted from 1-3.
According to DOT:10.5772/intechopen.74605, [10] the TRM process enables to produce syngas that can be converted to methanol and dehydrated to DME. DME synthesis based on syngas formed by TRM does generate H20 instead of CO2, as the main by-product.
The TRM is a synergistic combination of the endothermic CO2 and steam reforming reactions (5) and (6) with the exothermic oxidation of CH4 (natural gas), reactions (7) and (8). The reactions occurring are presented below and they are carried out in a single reactor:

(5) CO2 + CH4 4 2H2 + 2C0 (247.3 kJ x molt)

(6) H20 + CH4 4 CO + 3H2 (206.3 Id x molt)

(7) CH4 + 1/202 4 CO + 2H2 (-35.6 Id x molt)

(8) CH4 + 02 4 CO2 + 2H2 (-880 Id x molt) In addition, during the tri-reforming process, methane cracking (9), CO
disproportionation (10), water-gas shift (11) and complete oxidation of carbon reactions occur simultaneously (12).

(9) CH4 4 C + 2H2 (75 Id x molt

(10) 2C0 4 C + CO2 (-172 Id x molt)

(11) CO + H2O 4 CO2 + H2 (-41 Id x mol-1)

(12) C + 02 4 CO2 (-393.7 Id x molt) An example of composition of feed gases, including CO2, reaction (13), that TRM can convert into a syngas for methanol synthesis (14) followed by dehydration to DME (15) is outlined below. In this example no attention has been paid to energetically optimize the process. In a commercial plant generating syngas, energy optimization would receive considerable attention, equations (5-12).

(13) CO2 + 4CH4 + 2H20 + 1/202 4 5C0 + 10H2

(14) 5C0 + 10H2 4 5CH3OH

(15) 5CH3OH 4 2.5 CH3OCH3 + 2.5H20 "DME-based Extraction" plants recovering from the reservoir 100,000 bb bitumen/DME product per day will contain approximately 2,400 metric tons DME and 12,320 metric tons bitumen. The DME used for extraction will contain 1-3 wt% methanol. Production of DME containing small quantities of methanol reduces DME production cost and lowers the kinematic viscosity of the bitumen/DME dilbit. At atmospheric pressure the methanol contained in DME shall delay desorption of DME from the bitumen/DME dilbit. Synthesis of methanol and dehydration to DME, reactions (14) and (15) essentially do not generate CO2. The recovery of bitumen (12,320 metric tons/day) associated with electric energy consumption by the recovery plants due to pumping and heating is equivalent to emitting approximately 1,620 tons CO2 per day. The estimates based on reactions (13-15) show that due to CO2 recycling and utilizing the generated DME, the 1,620 tons CO2 to be emitted can be reduced to 700 tons CO2 per day or 0.007 tons CO2/barrel of dilbit. Incorporating the TRM into the ICF enables utilization of most of the generated 700 tons CO2 for producing the syngas required for DME synthesis.
Urea production (fourth bullet) generates demand for nearly pure CO2 generated by oxy-combustion of DME in a two-stroke Diesel engine. Ammonia required for urea synthesis is produced as a by-product of co-gasification of blends of coal and residue from bitumen distillation. Urea production from CO2 and NH3 generated during coal gasification has been commercialized in North Dakota Gasification Plant (NDGP).
Application of CO2 generated by NDGP has been successfully carried out for years in Saskatchewan for EOR (fifth bullet). Oxy-combustion of DME in low speed Diesel engines generates nearly pure CO2 that is suitable for EOR. EOR has significant potential in Alberta and Saskatchewan for recovery of conventional crudes from depleted conventional oil wells.
Geothermal heat recovery (sixth bullet) using CO2 instead of steam is gaining momentum. Northern Alberta is blessed with a huge geothermal heat potential. Various versions of geothermal heat recovery are being field tested in different jurisdictions including Alberta and Saskatchewan. Generation of electric power by DME oxy-fired two-stroke Diesel engine looks particularly attractive due to its capability to directly convert DME oxy-combustion heat into electricity (48-52%) and steam (around 40%) while quantitatively collecting nearly pure liquid CO2. Integration of this technology with utilization of generated CO2 for geothermal heat recovery combined with capture of some of the CO2 in the reservoir shall be of interest to Alberta and the bitumen industry.
The ICF for DME and electric power production could utilize the CO2 supplied by the off-site emitters.
Due to its capability to recycle and utilize CO2 for methanol or DME synthesis or urea production or carbon-free electric power generation, the ICF supplying DME and electric power for "DME-only extraction" plants would be converted into a zero carbon emission, low-cost energy producing conglomerate.
Apart from highly effective DME performance in in-situ bitumen recovery, DME
outperforms and shall replace any conventional Diesel fuel. In California the exhausts from combustion of the conventional Diesel fuel are classified as carcinogenic. It is allowable in California to fire diesel engines using DME

generated from biomass. DME synthesized from on-site generated CO2 shall be equally if not more acceptable. Low-cost DME is also a desirable option for replacing the LPG.
Prior to converting "DME-based Extraction" into a low-cost energy producing conglomerate the "DME-based Extraction" would have to be implemented and commercialized in order to confirm the reliability of the data required to embark on expanding the ICF.
The co-gasification is an adaptation of the Lurgi/BG moving bed technology for caking charges. The technology has been extensively tested in a large piloting scale, using caking coals and is available for commercial application.
The direct DME synthesis, reaction (4), yields high purity DME at a low cost of US$ 60-90 per ton (2007 US$) provided it is carried out in a large scale using low cost syngas. It generates CO2 as the main by-product [11].
(4) 3C0 + 3H2 4 CH3OCH3 + CO2 The co-gasification of a blend of coal and a bitumen distillation residue enables generation of raw syngas that after clean-up can be converted into DME using either direct (4) or indirect (via methanol) process.
China is a leader in cleaning the raw syngas generated by coal gasification for DME synthesis. Apart from syngas the co-gasification generates distillable crude oil characterized by high octane number. The distillable crude oil yields are equivalent - in terms of mass - to the distillation residue contained in the gasified blend. The distillable portion of the bitumen combined with the distillate from co-gasification equals the mass of the bitumen recovered from the reservoir by "DME-based Extraction". The co-gasification can be carried out under conditions that eliminate generation of any non-salable by-products.
Generation of oxygen and DME, reactions (1) and (3) will significantly reduce bitumen recovery cost and enables to lower the cost of bitumen/DME dilbit to that of the least expensive conventional crude oils.
1.41 Partial Upgrading of Bitumen A partial upgrading process based on co-gasification of blends composed of coals and an asphaltenic fraction-rich residue from atmospheric/vacuum distillation of bitumen is being protected by CIPO patent application # 2,915,898. An alternative partial upgrading process based on DME
utilization is being investigated.
2.0 Description of the Preferred Embodiments: DME/Water Blends for Generation of Low Cost Hydrogen, Electric and Mechanical Power In the 1950s the United States government embarked on a project to evaluate the potential of hydrogen energy for replacing the combustion of fossil fuels. In the 1960s it was demonstrated that catalytic dehydrogenation of coal at near ambient temperatures enabled generation of a large volume of hydrogen at an acceptable cost. The second phase of the project was aimed at identifying the optimal solutions for hydrogen handling, storage and transportation including pipelining and shipping. No satisfactory solutions for hydrogen storage and shipping were identified.

In October 2004, the US Los Alamos National Laboratory issued a report [12] on hydrolysis/steam reforming of DME.
DME can be readily handled, stored, transported and converted into hydrogen [12-16]. Conversion of DME into hydrogen by hydrolysis/reforming with steam, equation (17), can be carried out under very mild conditions. As opposed to natural gas (CH4) reforming, equation (6), DME's hydrolysis/reforming is releasing a relatively large volume of hydrogen, equation (17).
(17) CH3OCH3 + 3H20 4 6H2+ 2CO2 (6) CH4+ H20 4 3H2 + CO
Conversion of CH3OCH3 (DME) into liquid can be readily accomplished by pressurization (0.45 MPa) only.
Converting natural gas into liquid (LNG) followed by shipping, depressurizing and converting the LNG
back into gas is an expensive and cumbersome process.
Our review of the scientific and technical information on the hydrogen economy indicates that so far no promising solutions have been identified for hydrogen storage and shipping.
The cost of DME production by direct synthesis [11] has been estimated by Japanese technology developers at US$60-90/ton or US$7-11/barrel (2007 US$).
In addition to DME being identified and patented in Canada [1, 21 as the most promising solvent for in-situ bitumen recovery, DME is very promising as a hydrogen source. The production cost of DME has an effect on bitumen recovery and hydrogen generation costs.
DME's impact on human health and the environment has been tested extensively by the US EPA [4]. It has been confirmed that DME is nontoxic, non-carcinogenic, non-teratogenic and non- mutagenic [17].
Accidentally spilled DME readily evaporates from water or soil and decomposes in the atmosphere over 24-72 hours into H20 and CO2.
The suitability of DME for storage, transportation and utilization is of no concern. The DME production cost could be reduced by employing the CO2/H20 blend (2:4 molecular ratio) for methanol synthesis (1), which is followed by dewatering to DME (3).
(1) 2CO2 + 4H20 4 2CH3OH + 302 (3) 2CH3OH4 CH3OCH3 + H20 According to recent publications [9], reaction (1) takes place at ambient temperature and atmospheric pressure in the presence of Cu2O catalyst. Additional experimental work is required to confirm that process (1) can be scaled-up and its kinetics accelerated. Reaction (3) is a commercially applied dehydration of methanol to DME.
The reports [12] & [13] reveal that optimal conditions for DME steam hydrolysis/reforming as presented in reaction (17) are: a steam/DME mass ratio of 1/(1.2-1.5), an ambient (0.1 MPa) pressure, a temperature of +200 C and an alumina or zeolite based catalyst. The report [12] concludes that "thermodynamically, the DME processed with steam can produce hydrogen-rich fuel cell feeds with hydrogen concentrations exceeding 70%." Utilization of hydrogen for energy generation offers realistic and practical solutions for resolving the problems associated with climate change and bitumen industry.
DME could be exported to foreign markets by using proven LPG and LNG handling and transportation technologies. At the customer's site the DME would be converted, at very mild conditions, into hydrogen by blending with water and subjecting the blend to hydrolysis/reforming.

There are many economic and environmental benefits resulting from such an approach to hydrogen generation: the transportation costs are limited to DME transportation only, there is no need for developing new infrastructure for hydrogen handling, water available on the hydrolysis/reforming site is blended with DME, about 55% hydrogen is generated from water, DME recovered from bitumen/DME
blends can be mixed with water and turned into hydrogen at minimal energy input.
The Alberta bitumen industry has acknowledged that SAGD has to be replaced in order for the industry to meet economic and environmental requirements [19]. We propose that the best option is to replace SAGD steaming with DME extraction. Lowering the production cost of DME will enable a reduction in the cost of bitumen extraction and transportation. DME can be used for extraction as well as a diluent for transportation.
Though the reaction presented by equation (1) has not been demonstrated in a large scale yet this reaction offers the potential for a significant reduction in the cost of DME
production.
An option that is more advanced for commercial scale application is based on CH4 (natural gas) reforming using CO2, equation (5).
(5) CO2 + CH4 - 2C0 + 2H2 CO2 is the main by-product of direct DME synthesis, equation (4). Recycling and converting the CO2 into equimolecular syngas (CO/H2=1/1) required for DME direct synthesis will reduce the demand for natural gas and the cost of DME synthesis.
An alternative route is based on reacting an equimolar blend of CO2/CH4 over TiO2 catalyst supported on A1203 with the active phase modified by Ra and W03. The route provides 97%
conversion of CO2 into methanol and small amounts of formic acid, acetic acid and ether (16). The methanol can be readily dehydrated to DME generating H20 as the main by-product. This route has not been tested in a commercial scale.
Auto-thermal reforming that involves reacting natural gas (CH4) with CO2 and oxygen, reaction (18), has been developed to a commercial scale. The reaction is driven by generated heat and substitutes a portion natural gas with CO2.
(18) 2CH4+ 02 + CO2 4 3H2 + 3C0 + H20 + heat The auto-thermal reforming can be carried out in a compact, limited footprint plant. It requires low investment, its economy increases with scale-up, the operation is soot-free and flexible (short start up periods and fast load changes). Auto-thermal reforming combined with the Japanese direct synthesis of DME has the capacity to utilize CO2, reduce natural gas consumption and eliminates CO2 emissions and carbon tax payments A low DME production cost will rejuvenate the Alberta in-situ bitumen recovery industry, play a significant role in reducing hydrogen production cost and the transition from bitumen to a hydrogen-based energy economy.
A different approach to developing the hydrogen economy has been conceived in Germany and has become the basis for the "Helios" project to be developed in Saudi Arabia. The "Helios" project is expected to play a major role in production of green hydrogen to be exported to Europe. It is based on electrolysis of water using green electricity generated by solar panels and wind mills. The generated hydrogen is to be synthesized into ammonia (NH3). Liquid ammonia will be exported, delivered to a selected site and decomposed into nitrogen (N2) and about 60vo1.% H2. The expectation is that hydrogen will likely require clean-up in order to be fed into fuel cells for electric power generation.
The cost of "green ammonia" synthesis (solar panels and wind mills as sources of energy for the synthesis) to be carried out in Saudi Arabia is estimated at about US$250/tonne-NH3. The cost of NH3 decomposition and clean-up to generate green hydrogen remains uncertain.
Liquid DME can be readily pipelined and shipped and has been shown to be an effective corrosion preventer [13]. Either LPG tankers, tankers equipped with pressurized containers or with vapors recirculating systems can be employed for DME shipping. DME delivered to overseas markets can be utilized for a variety of applications. Apart from being a source of hydrogen, DME is a replacement for Diesel or cooking fuel or LPG diluent to effectively reduce its price. Under optimum processing conditions the DME/water blend will generate +70vo1.% H2, 20-25vo1.% CO2 and less than 1vol.% CO [12].The generated gaseous product can be freed from CO2 and CO using commercially available technologies thus yielding a gas containing around +99 vol.% H2.
Shipping the DME in tankers offers another opportunity for DME utilization.
The tankers can be equipped with a propulsion system powered by electricity generated by oxy-combustion of DME in a low-speed 2-stroke Diesel engine equipped with a re-burning boiler and cryogenic CO2 condensation/storage system.
The engine converts about 50% of the generated heat directly into electric power. The electric propulsion is capable of eliminating any CO2, SO. and NO. and reducing carbon micro-particulates emissions by 95%.
An alternative approach is to develop a portable system to convert the DME
into hydrogen, separate and store the condensed carbon oxides, feed the clean hydrogen into fuel cells and employ the electricity generated to power the tanker.
DME and natural gas net calorific values are 4,620 and 5,040 Kcal/L or 14,200 and 8600 Kcal/Nm3, respectively. The conversion of natural gas destined for overseas export into LNG requires temperatures of -162 C. The cost of conversion is high and the LNG generated has to be shipped by employing specialty tankers. Reforming natural gas requires pressures of 0.3-2.5 MPa, temperatures in the range of 700-1000 C and typically a Ni-based catalyst.
DME is a near perfect Diesel fuel (Cetane # 55-60); natural gas has Cetane #
of 0. In terms of explosion limits both DME and natural gas are comparable. The export of DME from Canada to the Pacific Rim makes more economic and environmental sense compared to generating and exporting LNG.
By being involved into developing the technology for producing the lowest cost DME, the bitumen industry could not only produce bitumen at a rock-bottom cost and meet or exceed all environmental requirements but would also emerge as a major supplier of DME. Generation of nearly pure hydrogen via hydrolysis/reforming of DME appears to be technically and economically a promising approach to producing hydrogen for applications in fuel cell stacks. Preliminary estimates indicate that DME/water-based, as compared to "Helios" hydrogen production, shall be more acceptable.
It is of key importance that production of DME-derived hydrogen in Canada opens an opportunity for a smooth conversion of the Canadian carbon-based bitumen recovery technology into a versatile and sustainable carbon-free hydrogen-based energy industry of the future.
2.1 Production of Hydrogen via DME-Based Process versus Other Options In addition to employing DME as a source of hydrogen, three other options are considered at this time for large scale hydrogen production. They include: conventional natural gas reforming and two proposed and researched approaches of which both are to be based on water electrolysis using low cost electrical power generated by wind mills and/or solar panels. One of them, known as the "Helios" project, has been referred to in the preceding chapter (2.0). The other one to be commercialized in Australia is presently operated in a commercial scale based on Victoria's lignite gasification. The generated gas composed mainly of H2 and CO is freed of CO by membrane separation thus generating nearly pure hydrogen. The CO is released and oxidized to CO2 with atmospheric oxygen.
Subject to overcoming technical problems with hydrogen handling, the gasification is to be replaced with water electrolysis using green electric power. Shipping the liquefied hydrogen generated in Australia to overseas customers is being demonstrated by testing a small tanker specifically designed and constructed for this purpose.
The criteria for estimation of the value of generated hydrogen products are:
its cost, purity and the range of possible applications; application of hydrogen as a feed for fuel cells is most desirable. Hydrogen to be utilized for combustion does not require very high purity. Hydrogen to be fed into fuel cells (green hydrogen) has to meet high purity criteria and its production has to be based on the principles of sustainability. High purity is required to avoid fuel cell poisoning. The poisoning is typically caused by carbon containing impurities present in the feed material (e.g. natural gas).
Fuel cells have the capacity to convert the energy contained in the feed material into electricity.
Hydrogen is the most desirable material for conversion into electric power; thermal efficiency of converting nearly pure hydrogen into electricity is about 90%.
The cost of blue hydrogen to be converted into electric power shall be not higher than US$2/kg. The cost of the renewable green hydrogen to be fed into fuel cells shall be less than approximately USS4/kg or per gallon gasoline equivalent.
The green hydrogen produced by "Helios" might be unsuitable for fuel cells operation. It is uncertain what will be the impact of trace amounts of ammonia (NH3) in clean hydrogen on fuel cells performance.
Ammonia is a hazardous product, its handling and transportation exposes humans to serious health hazards including death.
Though the hydrogen generated by water electrolysis meets the purity criteria, the costs of its liquefaction and shipping from Australia in specialty tankers may appear to be an obstacle in meeting economic requirements.
Production of hydrogen by hydrolysis/reforming of DME (CH3OCH3) has been demonstrated in a laboratory [12] and confirmed in a commercial scale [15]. The main by-product (CO2) and minute quantities of CO can be readily separated from the generated hydrogen by employing available commercial technologies.
DME can be inexpensively and safely delivered to any destination. At a selected site it will be diluted with water and the blend subjected to hydrolysis/reforming. Over 50% of generated hydrogen is derived from water and the balance from DME. The hydrolysis is the primary reaction leading to hydrogen formation. Hydrolysis makes it possible to drive the reaction at very mild conditions and prevents generation of carbon containing contaminants (+C1) that are present in products of high temperature reforming of natural gas. No C-C bonds are present in DME; water does not contain carbon atoms.

Cleavage of C-C bonds requires a lot of energy and is typically accompanied by side-reactions resulting in the formation of volatile contaminants. Natural gas contains 5-15% of carbon such as C2, C3, C4; their reforming generates difficult to separate gaseous contaminants. The +99vo1.%
hydrogen fed into fuel cells is expected to be satisfactorily converted into electric power at very high thermal efficiency.
The Japanese government (METI) had funded a large scale (100 tons/day) direct DME synthesis piloting facility. Mitsubishi Corporation acquired all rights to the technology and has brought its development to commercial stage. The optimal cost of DME production by this technology has been estimated at USS7-11/barrel (2007 US$). The cost of syngas preparation is included into the cost of DME synthesis. Reaction (3) summarizes the principle of the catalytic DME synthesis.
(3) 3C0 + 3H2 --> CH3OCH3 + CO2 DME (CH3OCH3) production cost can be further reduced by on-site recycling and utilizing the CO2 - the main by-product of reaction (3). Auto-thermal reforming is commercialized and suitable for this purpose.
It results in reducing natural gas consumption, provides the heat required for driving the process, reaction (18), and generates the syngas required for DME synthesis.
(18) 2CH4 + 02 + CO2 3H2 + 3C0 + H20 + heat The route to DME synthesis, reaction (1), via methanol dehydration, reaction (3) is the most promising route to future DME synthesis. Developing this route to the commercial stage shall be of utmost importance to Canada.
(1) 2CO2 + 4H20 --) 2CH3OH + 302 (3) 2CH3OH CH3OCH3 + H20 Reaction (1) delivers oxygen required for the application of a low speed DME
oxy-fired Diesel engine that, in addition to other functions, enables quantitative collection of generated CO2. Reactions (1) & (3) open an opportunity to eliminate the demand for natural gas reforming and formation of equimolar syngas to produce DME. Reaction (1) has the potential to reduce the DME, bitumen and hydrogen production costs to a rock-bottom level. It would also provide additional profits for DME producer(s) by utilizing CO2 supplied by emitters who are facing huge carbon tax payments unless they identify a solution to sequestrate their CO2 emissions at acceptably low cost.
2.2 On the economics of DME-Based Hydrogen Production The DME-based hydrogen production includes generation of DME, hydrolysis/reforming of a DME/water blend to form hydrogen rich gas, removing carbon oxides ¨ if required - from the gas thus resulting in +99vo1.% hydrogen product. The cost of generation of equimolar syngas CO/H2=1/1 (vol. ratio) followed by the Japanese direct synthesis to DME has been assumed to be approximately US$10/Parrel of DME.
The cost of DME hydrolysis/reforming including the removal of carbon oxides from the hydrogen has been tentatively evaluated at US$0.70/kg hydrogen. This cost is equivalent to the cost of conventional steam reforming of natural gas at its source. The cost of conventional reforming of natural gas supplied by off-site sources does increase the reforming cost by US$(1-2)/kg hydrogen.
DME hydrolysis/reforming proceeds at very mild conditions. Conventional hydrogen reforming produces a blue non-sustainable product. Its clean-up is not economically viable. The literature [21] indicates that carbon oxides present in the +70vo1.% hydrogen generated from DME/water blends can be separated by allotrope membranes. Other methods recommended for removal of these two compounds from

16 hydrogen include: pressure swing adsorption, a cryogenic distillation method at a low temperature, amine gas sweetening solutions, and absorption of CO2 with other absorbents.
The cost of DME production can be reduced by replacing, either partially or completely, the usage of natural gas with CO2 for syngas generation. The auto-thermal reforming, equation (18), shall reduce this cost by about 50%. By advancing the Nazimek/Yimin concept [9] of reacting CO2 and H20 to form DME;
a large portion or a total cost of methanol synthesis would be paid off by large CO2 emitters, equations (1), (2) & (3). Instead of paying a huge federal carbon tax, the CO2 emitters would be much better off by supplying CO2 to DME manufacturers based upon a pre-negotiated long term service agreement for CO2 sequestration.
Within a wide range of DME production costs (US$0.00-100/barrel) the hydrogen product cost might be reduced to US$0.70-4.31/kg hydrogen.
1. at US$0.00/barrel DME3 US$0.00/kg hydrogen + US$0.70/kg hydrogen 3 US$0.70/kg hydrogen 2. at US$50/barrel DME 3 US$ 1.80/kg hydrogen + US$0.70/kg hydrogen -->US$
2.50/kg hydrogen 3. at US$100/barrel DME 3 US$ 3.61/kg hydrogen + US$0.70/kg hydrogen 3US$4.31/kg hydrogen Comments reg.: 1. 2. & 3:
= Reg.1.: The cost (US$0.70/kg hydrogen) of DME synthesis, hydrolysis/reforming of the DME/water blend and CO2/C0 removal might be underestimated by up to US$2.00/kg hydrogen;
= Reg.1.: The cost of DME synthesis can be reduced to US$10.00 to US$0.00/barrel-DME due to recycling and conversion of the on-site generated CO2 into DME;
= Reg. 2. & 3.: The costs of DME synthesis (US$50/barrel DME and US$100/barrel DME) can be significantly reduced depending on volumes of CO2 supplied from off-site emitters for sequestration;
= Green hydrogen production cost from DME/water blend via hydrolysis/reforming is expected to be lower as compared to other proposed green hydrogen generation technologies;
= Production of low-cost hydrogen from DME/water can be carried out at any site that can be supplied with low-cost Canadian produced DME or Bitumen/DME blends;
= The application of DME for bitumen recovery and generation of hydrogen/electric power has the potential to convert Canada into a major sustainable energy hub.
The estimates for energy consumption by the gasoline and hydrogen powered automobiles are presented below:
1. The gasoline powered automobile:
= Typically consumes 70 L (52.5 kg) gasoline per 700km;
= Gasoline heat combustion and specific gravity are about 45MJ/kg and 0.75kg/L, respectively;
= The energy contained in 701 of gasoline is about 2,363MJ, equivalent to 338MJ/100km;
= Reportedly the average consumption of energy by an automobile is 248MJ/100km;
2. The hydrogen powered automobile:
= A 97.5L high pressure (690 atm.) fiber-composite tank contains approximately 6.0kg hydrogen;
= Hydrogen's combustion heat is 141.6MJ/kg; the energy contained in 6kg hydrogen is 850MJ;

17 = Hydrogen powered engine reportedly requires 115.2MJ/100km;
= The range of the automobile powered with 6.0kg hydrogen is about 738km.
In terms of range (distance driven) the gasoline and green hydrogen driven automobiles are comparable.
The hydrogen powered automobile will not generate emissions. The cost of green hydrogen (US$4/kg hydrogen) to fill the 97.5L tank pressurized to 690 atm. amounts to about US$24. The market price of gasoline to fill the 701 tank amounts to about US$55 (2021US$). Reportedly the energy consumption by hydrogen automobile (115MJ/100km) is about 30% of that of gasoline automobile (338MJ/100km).
Hydrogen powered vehicles offer an ultimate solution to climate change and have the capacity to reduce the demand for energy. The costs of hydrogen distribution/marketing, developing and constructing the infrastructure required for hydrogen are unavailable. These costs will be significant. Green hydrogen, as opposed to DME/water blends, does not have the capacity to contribute much to lowering the cost of automobile powering. An automobile equipped with 1241 tank containing DME/water blend (about 1/1.2 mass ratio) at a pressure not exceeding 4.5 atm. shall outperform the hydrogen powered vehicle.
The DME/water blend powered vehicle would have to be equipped with a portable system for hydrolysis/reforming of the blend, separating carbon oxides - if required, installing fuel cell stacks, a battery/alternator-based starter and an electric motor for converting electricity to mechanical energy.
Such system will generate 12kg hydrogen, twice as much as compared to that contained in 6kg of hydrogen pressurized to 690 atm. in a 97.5L tank. The DME/water tank contains approximately 69L
(464) liquid DME and 551 (55Kg) water. At US$10/barrel DME the production cost of DME contained in the tank will amount to about US$4.30. By recycling and utilizing the generated CO2 this cost will be reduced or eliminated thus providing additional profits to Canadian DME
producer. The conversion of DME/water blend to mechanical energy consumes about 25% of total energy of 1,700MJ generated by the portable system. The energy balance of 1,275MJ would extend the driving range of the DME/water blend powered automobile to approximately 1,100km. Approximately half of this distance would be driven on nearly zero cost hydrogen generated from water. The developed portable system would provide a simple, safe and practical solution to powering any transportation vehicles or stationary electric power generation systems. Powering the whole transportation industry with DME/water blends, including aviation and sea transportation, looks promising and does not require developing and constructing hydrogen infrastructure.
2.3 Benefits of DME-Based Heavy Crudes Recovery and Hydrogen Production DME is the key to optimizing the performance of bitumen/heavy crudes recovery and a source of inexpensive either +70vol.% hydrogen containing CO2 and -1vol.% CO or a nearly pure +99vo1.%
hydrogen generated from DME/water blends. It is expected that such hydrogen can be employed as feeds for fuel cells to generate electric power at up to 90% energy efficiency. The DME can be produced and the hydrogen/electricity generated regardless of whether the wind is blowing and/or the sun shining. DME can be stored, handled and transported using the existing infrastructure developed for gaseous/liquid fossil fuels. DME has to be delivered to a site where the hydrogen generation takes place.
On the site the DME will be blended with water and hydrolyzed/reformed.

18 The DME can be delivered as such to hydrogen production site or in the form of bitumen/DME dilbit.
Bitumen can be utilized for production of asphalt for roadways construction, petrochemicals, carbon fibers, a feed for refining to transportation fuels and so on. DME can be employed as super-clean, low cost Diesel or cooking fuel, a substitute for LPG or as feedstock for conversion to +99vo1.% hydrogen or electric power [14].
The upgrading of bitumen separated from bitumen/DME dilbit for transportation fuels production will emit some CO2. The CO2 emissions can be offset by generation of large volumes of hydrogen from DME
separated from DME/bitumen blends. No other petroleum blends have the capacity to offset CO2 emissions generated by their upgrading/processing. That increases the value of, and the demand for, bitumen/DME dilbit of which the usage is protected. The bitumen/DME producers will profit by charging the importers for both the bitumen and the DME. Both bitumen and DME can be employed for a variety of applications. The producers will also profit by replacing expensive condensate with DME for bitumen transportation. DME enables bitumen extraction, thinning and transportation.
Eliminating the need for condensate reduces the bitumen producers' cost by around US$20/barrel of bitumen.
Fuel cells powered with hydrogen are of particular interest to the transportation sector. They were employed in electric vehicles including Hundai's Tucson (2014 year) and Toyota's Mirai FCEVs (2015 year). Steps are to be taken for planning and developing hydrogen infrastructure for powering electric vehicles equipped with fuel cells in the whole of the United States. As compared to generating, pipelining and shipping pure hydrogen the DME route offers a much less expensive and practical solution to carbon-less economy.
Pure hydrogen in portable power generation CHP fuel cells eliminates CO2 emissions, deposition of carbon and extends the life time of fuel cells operation [14-16]. CHP systems have been installed all over the world for a variety of applications including stores, hospitals, corporate facilities at any sites ranging from 200kW-1MW.They require highly pressurized pure and expensive hydrogen.
DME shall improve transportation vehicles performance provided they are equipped with systems enabling DME/water conversion into mechanical energy as outlined in chapter 2.2. The production cost of 46kg DME blended with water (1/1.2-1.5 mass ratio) in 124L tank will generate about 12kg of hydrogen and shall be in the range of just a few 2021 US$. The driving range of such a vehicle will be extended to approximately 1,100 km. The market cost for gasoline required to drive the gasoline automobile for a distance of 1100 km would amount to around US$110 (2021 US$).
The Japanese direct DME synthesis integrated with auto-thermal reforming provides a strong argument in favor of developing large scale and low cost DME production in Canada. The DME output shall be about 5,000 tons/day to bring maximal benefits from a large, commercial scale production. Initially, a singular 1,000 tons/day direct DME synthesis reactor shall be constructed. The construction of such singular reactor shall be preceded by successful demonstrations of the "DME-assisted SAGD" and the "DME-based Extraction" plants. After confirmation of the "DME-based Extraction" performance additional 1,000 short tons/day reactors would be constructed on the ICF site.
That would provide the basis for developing specifically Canadian expertise in a large scale DME
production and transition from carbon-based bitumen to carbon-free, sustainable hydrogen/electric power economy.

19 References:
1. Canadian Patents/Patent Applications: #2,652,930; #2,604,058; #2,936,649;
#2,915,898, 2. Canadian Patent Application: #2,936,649; filed on 2016/07/20, entitled "Systems for SAGD
Performance Improvement by Application of Amphoteric Solvents", 3. GU Petroleum Consultants, "Understanding Bitumen Pricing" Posted by Bill Spackman, May 18,2016, 4. DuPont SHE Excellence Center, "Dimethyl Ether (DME)", prepared for EPA, October 11, 2000, 5. Canadian Patent Application: #2,915,898, filed on 2015/12/21, entitled "An Integrated Method for In-Situ Recovery and Upgrading Bitumen/Heavy Oil to Distilfable Liquids and Generating Super Clean Diesel and Electric power", 6. Li Z., Firoozabadi A. Z., Energy Fuels, 24, 1106 (2010), Akbarzadeh K., Ayatollahi S., Moshifeghaian M., Alboudware H., Yarraton H. W., Journal of Can. Petrol. Tech., 43, Sept.
2004, AI-Sahhaf T. A., Fahim M. A., Elkilani A. S., Fluid Phase Equilibria 194497, 1045 (2002), Sato S., Matsumura A., Japan Petroleum Institute, 53, (4) 256, (2010), 7. Alberta Innovates, 2017 Report entitled "Study of Solvent-Assisted In Situ Bitumen Recovery"
8. Google, <envirotechdme.com> , 9. Nazimek D. and Czech B., 10P Conference Series: Materials and Science Engineering, E-MRS, Fall Meeting 13-17, 2010, Vol. 19, Warsaw, Poland; Yimin Wu, Waterloo News, "News"
November 2019, 10, DOT:10.5772/intechopen.74605, 11. Ohno, Y., Edited by Japan DME Forum, DME Handbook, 2006 and DME Handbook-Supplement, 2011, 12. Los Alamos National Laboratory (LANL), 2004 Report LA 14166, 13. Semelsberger, T. & Borap, R., LA-14166: Thermodynamics of Hydrogen Production from Dimethyl Ether;
14. Fact Sheet ¨ Fuel Cells I White Papers I EESI;
15. Hydrogen production by Steam Reforming of DME in a large scale CBF
Reactor;
16. International Journal of Hydrogen Energy, issue 46, (40), pp 15865-15876, Dec. 14, 2015, 17. Industrial Hygiene and Toxicology, 461 Ed., New York, John Wiley and Sons Inc. 1993-94, 18. Google, Fuel Cells, Department of Energy, 19. Accelerating NHRTS&I, COSIA, CRIN, PTAC, CHOA & CSUR, 2020,

20. Erdohelyi, A. Catalyst 2021, 11, 159, pp 1-30

21. Rezaee, P & Naeij, H. R., Scientific Reports 10, Article number13549(2020) TABLE 1. Assumptions for GHG Reductions Estimate*
SAGD ¨ Baseline Assumptions DME ¨ Project assumptions CO2 sources : 2 (A & B Value CO2 sources: (A & B) Value Facility annual output 109.5mln bb/y Facility annual output 109.5mln bb/y 17.41 MinVy 17.41 Mm3/y A: Consumption of electric energy 295 TJ/d A: Electric energy for fluids pumping 56 TJ/d generated by natural gas 56x 10121/d/47,700 rn3id = 1174 combustion Thermal efficiency of NG fired 42% Thermal efficiency (for DME-fired co-48%
power plant: generation Diesel plant) Electrical energy consumption per 1,019 Milm3bit El. energy used per barrel of bitumen 193 MJ/m3 bit barrel of bitumen produced produced- 8.5 kWh (from numerical (published data) 45 kWhibbt analysis equal 19% of SAGD process) CO2 emission factor from NG: 0.000263 CO2 emission factor for DME: 1.913 kg kgCO2/kcal (US EPA, 2008) 0.000263 kgCO2/kcal CO2/6900 kcal (0.0002775 kgCO2/kcal) = 0.0663 0.063 kgCO2/MJ 0.0663 kgCO2/MJ
Other data kgCO2/MJ
Nat gas CO2 emissions 0.052.8 kgCO2/MJ (3,607 kcal/ kgc02) 15.09 MJ/kgco2 Other 0.0503 kgCO2/MJ 1/0.0663 kgCO2/11/44.1=15.09 Mi/kgco2 B: CO2 emissions from NG B: Electric energy for reservoir heating combustion to provide heat for steam generation CO2 originates from boilers only 40 Kt/d Electric energy conversion to heat 100% 38 TJ/D
(SECT technology) Saturated wet steam 20 wt.% Reservoir composition: 12 wt.%
bitumen, Composition 12 wt.% water, 76 wt.% minerals (silica & 12%+12%+76%
clay) NG heat value ** 34,355 Wrn3 Temperature increase: (10 C -70 C) 70 C
Boiler efficiency: 80% Thermal efficiency of Diesel engine 48%
Steam injection pressure 2.5 MPa SOR: 3.5 CO2 emission factor for NG: 1.891 kgc02/m3 Bitumen reservoir temp 80-100 C Bitumen reservoir temp 50-Bitumen recovery from reservoir 50% Bitumen recovery 80-90%
Bitumen drainage capacity 1 Bitumen drainage capacity 3-4 times (47.7 Km3/d) faster Condensate content in pipeline ¨30% DME content in pipeline 15-17%
Breakeven cost USS 40 Breakeven cost US$ 7-8 *Carried out for 300,000 bpd plant; 100% availability;
**Other gas: Methane - 35.95 MJ/Nm3 or 49 IVIJ/kg Table 2. Technologies Operational Parameters SAGD Technology Baseline Conditions DME Technology Operational Conditions Parameter Value Parameter Value Bitumen production 47.7 Kt/d Bitumen production 47,7 Ke/c1 Thermal energy in steam delivered to 338.4 TIM
Electrical energy delivered to bitumen 38 TJ/d bitumen reservoir reservoir for heating Natural gas used by boiler for steam 17.19 Mm3NG/d DME used by local electrical energy generator 6.75 Kt/d generation (boiler efficiency 80%) (diesel engine eff. 48%) (3.29 Mm3/d) CO2 emissions related to boiler 32,500 t/d CO2 emissions related to local electrical not emitted operation energy generator used for reservoir heating but recycled (eff. 48%) Consumption of electric energy by water 295 TIM
Consumption of electric energy by fluid 56.05 TJ/d pump (from grid) pumps (from local Diesel engine generator) Total electrical energy used by plant 94 TJ/d (pumping and heating) Diesel engine eff.48%
Daily CO2 emission related to pumps fed 7,238 t/d Daily CO2 emission from local electrical 6.52 kt/d from a grid (effi.42%) generator (eff. 48%) not emitted but recycled recycled Process water demand (2.5 b /bb bit) 120 Km3/d Process water demand No water used Total CO2 emissions (ref. pump @ boiler) 39.78 kt/d Total CO2 emissions (ref. pump+heater) 6.52 kt/d (14.5 Mt/y) (not emitted but predicted to be recycled to (2.38 Mt/y) plant) Amount of condensate used (30% blend) 20,700 t/d Amount of DME used (15% blend) 8,528 t/d Table 3: Summary of information on DME-based Bitumen Recovery Technologies DME-based Key Features Major changes in plant Expected Performance Technologies operation 1. "DME-assisted Applies DME Admixes DME to SAGD's Increases overall bitumen SAGD" (DME-SA) solvent in a steam or replaces recoveries and recovery rates;
The basic technology SAGD plant hydrocarbons with DME in no need for condensate to hydrocarbon-assisted SAGD transport bitumen/DME
dilbit 2. "DME-based Bitumen Eliminates natural gas It is expected to reduce plant extraction" (DME-E) recovery based combustion, CO2 emissions, capital cost, as compared to The advanced on extraction steam generation & process SAGD, by up to 80% and technology with DME water treatment, applies breakeven costs by 65-80%, instead off electric in-reservoir heating increases overall recovery of steam assisted of DME; reduces energy bitumen from 50% to 80-90%
drainage consumption by 10 times and extraction rates by 300-and recycling of injection 400%
liquids by 30 times 3. "Integrated DME- The expansion The expansion of the whole Among the 5 options based extraction" of the ICF to facility is limited to ICF; no identified for optimizing the (I-DME-E) produce value- changes to bitumen recovery performance of the ICF, The optimal added products plants; scaling up the scaling-up the process technology by processing CO2-DME process will CO2---)DME followed by DME
the by-products convert the whole facility steam reforming is expected formed on ICF (ICF and recovery plants) to provide optimal results;
site; scales-up into sustainable & versatile scaling-up the process the conversion energy system; CO24DME is expected to of CO2 -)DME significant reduction in DME reduce bitumen recovery cost to maximally production cost by scale-up below that of conventional reduce the costs of CO2-DME conversion crude oils and bridge the of DME and could enable handling and transformation of bitumen bitumen transporting the DME and its recovery industry into a DME
production reforming to hydrogen and hydrogen production hub

Claims (4)

What is claimed is:

1. An advanced/integrated technology to manufacture and apply an amphoteric Dimethyl Ether (DME, CH30CH3) solvent for in-situ recovery of bitumen/heavy oils and generation of hydrogen.

2. The advanced/integrated technology includes:
2.1 DME manufacturing using direct and indirect processes; utilization of the commercially proven LPG and LNG infrastructure for DME storing, handling and transporting;
application of DME for in-situ bitumen/heavy oils recovery.
2.1.1. Manufacturing DME from equimolar syngas composed of carbon monoxide and water (CO/H2 = 1/1 vol. ratio) by direct Japanese process comprising the steps of:
a) generating raw syngas by any of the unit processes listed below:
- conventional gasification of a subbituminous or bituminous coal or any blend therefrom or, - conventional reforming of natural gas using oxygen or steam or, - reforming of natural gas with CO2 or, - tri-reforming process or, - auto-thermal reforming of natural gas with CO2 and oxygen.
b) combining CO2 generated within ICF with CO2 acquired from off-site sources, utilize a portion of the combined CO2 for reforming natural gas with CO2, tri-reforming and auto-thermal reforming as listed under a);
c) processing generated raw syngas to convert it into clean, equimolar (CO/H2 = 1/1 vol. ratio) syngas for DME synthesis, d) utilizing, if required, the balance of the combined CO2 for synthesis of urea or for EOR
applications or for recovery of geothermal heat combined with electric power generation;
e) applying Japanese direct synthesis process to synthesize DME from the equimolar clean syngas.
2.1.2. Manufacturing DME by indirect process that involves methanol synthesis followed by dehydration of methanol to DME; the process will involve one or more of the unit processes listed below:
a) conventional steam reforming of natural gas followed by converting the syngas into methanol and methanol dehydration to DME;
b) reforming the natural gas by incomplete oxidation, synthesizing the generated syngas (CO/
H2 =1/2 vol. ratio) into methanol followed by methanol dehydration to DME;
c) co-gasifying a subbituminous or bituminous coal or a blend therefrom with heavy vacuum bottom/residue obtained by distillation of bitumen/heavy oil, as described by CIPO #
2,915,898, followed by cleanup of the raw syngas to clean syngas (CO/H2 =1/2 vol. ratio);
synthesizing the clean syngas into methanol and dehydrating the methanol to DME;
d) converting CO2 originating from ICF and off-site sources to methanol by catalytic hydrogenation followed by methanol dehydration to DME in methanol dehydration reactor;
e) catalytic photosynthesis of a blend composed of CO2 and water vapor (CO2/H20=2/4 vol. ratio) into methanol and oxygen followed by dehydration of separated methanol into DME and utilization of oxygen for reforming and for power generation by oxy-combustion of some DME
in low-speed Diesel engine;
f) passing the vapors containing water, DME and methanol from methanol dehydration reactor to rectification tower that produces DME containing 1-3 wt.% of residual methanol; separating the water collected in rectification tower bottoms from the methanol and recycling the methanol to dehydration reactor.
2.2. Manufacturing the hydrogen by hydrolysis/reforming DME/water blend; the manufacture and utilization of hydrogen includes:
a) utilizing the existing commercially proven LPG and LNG infrastructure for DME storing, handling and transporting;
b) exporting DME to customers interested in generation of low-cost +70voL%
hydrogen and nearly pure +99vo1.% hydrogen;
c) blending the DME on customer's selected site with water in 1/1.2-1.5 mass ratio;
d) subjecting the blend to hydrolysis/reforming at pressure of 0.1 MPa or higher, temperature of +200 C, in presence of alumina or zeolite-type catalyst;
e) utilize the +70vo1.% hydrogen gas as required;
f) free the +70vo1.% hydrogen gas from CO2 and minute quantities of CO by application of any commercial separation technology;
g) utilize the nearly pure +99vo1.% generated hydrogen as feed for fuel cells to generate electric power and distribute the electric power using the existing electric grid.

3. Employ the advanced/integrated technology for:
3.1. Applying DME for in- situ recovery of bitumen and/or heavy oil from their reservoirs;
using DME containing minute quantities (1-3wt_%) of methanol for bitumen extraction and dilution to reduce the cost of recovered bitumen thinning, handling and transporting; export the bitumen/DME blend to customers;
3.2. Recovering, at customer site, the bitumen from the blend and utilizing the bitumen for any application required including converting the non-asphaltenic portion of the bitumen to transportation fuels;
3.3. Converting the DME, recovered from the bitumen/DME blend, into hydrogen;
either combusting the +70vo1.% generated hydrogen product and utilizing the heat for any application required or employ the +99vo1.% hydrogen freed of carbon oxides as fuel cells feed to convert the hydrogen's heat energy into carbon-free electric power at around 90%
thermal efficiency; distribute the electric power using the existing electric grid;
3.4. Alternatively, employ the DME recovered from bitumen/DME blends on customer's site as replacement for LPG and conventional Diesel fuel; blend the DME into LPG to reduce its cost; replace conventional Diesel fuel in low- speed Diesel engines with DME to eliminate SO., NO. and to reduce carbon particulate emissions by 95% and prevent CO2 emissions;
3.5. Offset CO2 emitted from bitumen subjected to any type of chemical processing by converting the DME diluted with water into hydrogen; the said hydrogen converted into carbon-free electric power offsets CO2 emitted by bitumen processing - no other conventional crude oil dilbits can compete with bitumen/DME blends in terms of CO2 offsetting capacity;
3.6. Substitute maximal volume of natural gas with CO2 for generation of syngas required for DME
production by application of auto-thermal reforming, the substitution will result in reducing DME production cost thus resulting in lowering the cost of bitumen recovery and hydrogen generation;
3.7. Eliminate the usage of natural gas for generation of syngas required for methanol production and its dehydration to DME by improving the kinetics and scaling up the catalytic photosynthesis of CO2 and water.
Utilize the catalytic photosynthesis process to:
3.7.1. Generate methanol and oxygen from CO2 and water; the methanol is dehydrated into DME and the oxygen is utilized for a variety of applications; the CO2 originates from the ICF and from large CO2 emitters interested in avoiding carbon tax payments; CO2 eliminates the demand for natural gas and reduces or eliminates DME production cost;
conversion of CO2 originating from off-site sources to produce DME becomes a source of additional revenue for ICF operators; maximally reducing DME production cost reduces bitumen recovery and hydrogen production costs to a rock bottom level;
3.7.2. Eliminate the need for constructing a high voltage transmission line from the ICF to selected site in the Fort McMurray area to deliver electric power required by "DME-only Extraction" bitumen recovery plants for piping and in-reservoir heating; small volume of the DME delivered by pipeline to a selected site near Fort McMurray will be diluted with water and converted into clean hydrogen fed into fuel cells generating electric power to be distributed to individual DME-based bitumen recovery plants using existing electric grid;
3.7.3. Supply the electric power to the individual processing units operating within the ICF by application of the same type of electric power generation system as the one to be developed for the site near Fort McMurray (see 3.7.2.);
3.7.4. Utilize the oxygen generated in the ICF by catalytic photosynthesis for the following applications:
3.7.4.1. conversion of CO2 and natural gas into equimolar syngas (CO/H2=1/1 vol. ratio) by employing conventional auto-thermal reforming;
3.7.4.2. gasification of subbituminous or bituminous coals or blends therefrom;
3.7.4.3. co-gasification of subbituminous or bituminous coals or blends therefrom mixed with residues/bottoms generated by bitumen distillation;
3.7.4.4. in-complete oxidation/reforming of natural gas for generation of syngas (CO/H2=1/2 vol. ratio) that can be converted into methanol followed by dehydration to DME;
3.7.4.5. oxy-combustion of DME in low-speed Diesel engines for generation of electric power and pure CO2 that can be synthesized with NH3 generated by co-processing technology to form urea, a quality fertilizer;
3.7.4.6. tri-reforming of gases blended for generation of any type of syngas with CO/H2 vol. ratio in the range of 1-3.

4. Utilize the DME based technology for hydrogen generation to design and construct a portable/mobile and stationary systems that enable powering transportation vehicles based on energy generated from DME/water blends; the process includes the following steps:
4.1 Accumulating in a designated tank a blend of DME and water (1:1.2-L5 mass ratio) at pressure of 0.4-0.5 MPa;
4.2 Introducing in a controlled manner a stream of the blend to a pre-heated reactor operating at +200 C and around 0.1 MP for hydrolysis/reforming the blend in presence of alumina or zeolite-acid based catalyst;
4.3 Either feeding the hydrogen-rich gas composed of +70vo1% Hz, CO2 and -lvol.% CO into fuel cell stacks for converting into electricity or separating the hydrogen-rich gas from CO2 and CO
by application of a selected commercially available technology and feeding the nearly pure +99vo1.% hydrogen into fuel cell stacks for conversion into electricity at about 90% thermal efficiency;
4.4 Converting in electrical motor the electricity into mechanical power to power any type of transportation vehicles by employing the portable/mobile system; the same powering technique can be employed to power any stationary system;
4.5 Equipping the portable/mobile system with integrated battery- alternator device to enable the start-up of the portable/mobile system.