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This application claims priority from U.S. provisional patent application Ser. No. 61/088,038 filed Aug. 12, 2008. 
    
    
     BACKGROUND OF THE INVENTION 
     The general field of this invention is the production of heavy oil and bitumen from underground deposits, particularly tar sands deposits. More specifically, this invention relates to a method for bitumen or heavy oil recovery by in situ combustion that substantially decreases carbon dioxide emissions. 
     There are extensive oil sand reserves in many areas of the world, e.g. Alberta in Canada, Utah, Wyoming, and Colorado in the United States, and Venezuela. However, the very high viscosity of bitumen makes economically viable and environmentally responsible exploitation of these abundant resources very challenging. Conventional oils can be efficiently recovered without any need for heating to reduce their viscosity. Carbon dioxide injection can be used to reduce the viscosity of conventional oil and increase the quantity of oil recovered. However, substantial energy inputs are required to lower the viscosity of very heavy oil or bitumen in order to achieve reasonable production rates. This high energy input requirement increases the bitumen production cost and associated carbon dioxide emissions relative to conventional oil. As a result of the dwindling reserves of conventional oil, there has been a long-standing effort to develop methods to more economically exploit these reserves in an environmentally responsible manner. 
     Bitumen was initially produced by mining using the ‘hot water’ method (CA2004352) to extract the hydrocarbons from the mineral gangue. This method has four problems. First, mining requires disturbance of the land. Second, most bitumen reserves are too deep to be economically recovered by mining. Third, this method requires large quantities of scarce water. Fourth, this method has a high energy input requirement, which substantially decreases the net energy production and increases CO 2  emissions relative to conventional oil production. 
     The steam assisted and gravity drainage (SAGD) in situ bitumen production method (U.S. Pat. No. 4,344,485) is currently the most commercially successful method to exploit deeper bitumen reserves. This method uses a horizontal upper steam injection well and lower parallel bitumen production well. Although this method can economically produce bitumen at greater depths than mining, it also requires large quantities of water and energy for steam production. Boilers (US 2007/0266962) with indirect heating are typically used for SAGD steam production, which generally require a premium natural gas fuel and results in significant CO 2  emissions. U.S. Pat. No. 4,224,991 teaches an oxygen-fuel combustion method with water injected into the combustion region to control its temperature to produce steam for heavy oil production. In addition, direct contact steam generators can also advantageously use water to control flammability of the premixed O 2 -fuel feed (U.S. Pat. No. 6,206,684) or to cool the combustion chamber walls (U.S. Pat. No. 2,359,108). 
     It has long been recognized that in situ combustion bitumen production processes have the potential to solve many of the SAGD process problems by [1] producing, rather than consuming water, [2] using lower value bitumen components as an energy source, rather than an external premium fuel, [3] in situ upgrading of the bitumen, and [4] simplifying the recovery of CO 2 . In situ combustion processes typically have vertical oxidant injection wells and vertical (U.S. Pat. No. 4,722,395) or horizontal (U.S. Pat. No. 5,456,315) production wells. A wide variety of oxidants have been proposed for in situ production processes: air (U.S. Pat. No. 5,456,315), air-O 2  (U.S. Pat. No. 4,557,329), O 2 -water (U.S. Pat. No. 5,027,896), O 2 -steam (U.S. Pat. No. 4,133,382), O 2 —CO 2  (U.S. Pat. No. 4,410,042), and O 2 —CO 2 — steam (U.S. Pat. No. 4,217,956). Hydrotreating catalyst may be advantageously added to the production well for in situ bitumen upgrading using in situ produced hydrogen (U.S. Pat. No. 6,412,557). There have been modest efforts to utilize the off-gas from in situ combustion bitumen production processes. For example, U.S. Pat. No. 4,454,916 teaches the use of a highly enriched air oxidant (≧50 volume percent O 2 ) separating carbon dioxide from the off-gas from an in situ heavy oil production process to produce a low heating value fuel gas. 
     A number of factors make carbon dioxide capture and sequestration from conventional bitumen production processes impractical. First, the gaseous emissions from bitumen production processes invariably have very low carbon dioxide concentrations, typically about 15 molar percent. Second, bitumen production facilities typically have a large number of gaseous emission points. Third, bitumen production facilities have a much shorter economic life than most other large carbon dioxide emission sources like coal fired electrical power generation facilities. Unfortunately, bitumen production processes have high carbon dioxide emission rates. For example, mining and SAGD bitumen production processes have typical carbon dioxide emission rates of about 90 and 60 kilograms per petroleum barrel (kg/bbl) bitumen produced. As a result, carbon dioxide emissions from bitumen production will likely become a significant source of carbon dioxide emissions and have a significant impact on global warming. For example, bitumen production from Canadian oil sands is expected to increase from 1.3 million barrels per day in 2008 to about 4 million barrels per day by 2030. If conventional technology were used to meet this expected increase in market demand, then the associated carbon dioxide emissions should increase by about 60 million metric tons per year by 2030, or about 10% of Canada&#39;s 2006 total carbon dioxide emissions. Therefore, there is a clear need for a practical bitumen production method with much lower carbon dioxide emissions that is not met by the prior art. 
     SUMMARY OF THE INVENTION 
     The invention is a continuous bitumen in situ production method which comprises the following steps:
         a) purging non-condensable gases from the an oil sand reservoir with steam;   b) contacting a gaseous oxidant stream comprising oxygen, carbon dioxide, and steam with bitumen in an oil sand reservoir;   c) separating the production well product from the oil sand reservoir into bitumen, water, sand, and fuel gas streams;   d) producing a carbon dioxide rich gas by combustion of the said fuel gas with substantially pure oxygen;   e) utilizing substantially pure oxygen and a portion of said carbon dioxide rich gas as constituents of said gaseous oxidant stream; and   f) sequestering a supermajority of the balance of the said carbon dioxide rich gas into a depleted oil sand reservoir.       

    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is a simplified sketch of a well pair in an underground oil sand reservoir. 
         FIG. 2  is a plot of the effect of the oxidant oxygen content on the petroleum coke gasification temperature and the bitumen production thermal energy input requirement. 
         FIG. 3  illustrates a typical oxygen combustor and electrical power generation system. 
         FIG. 4  is a block flow diagram that illustrates the in situ bitumen production method with carbon dioxide capture and sequestration. 
         FIG. 5  summarizes the oil sand reservoir CO 2  production and sequestration capacity as a function of reservoir operating conditions properties. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       FIG. 1  is a simplified sketch of an underground oil sand reservoir. These oil sand reservoirs contain bitumen that is a hydrocarbon fuel with a high density (typically greater than 1 kilogram per liter), a high residua content (typically about 50 wt % yield of components with normal boiling points greater than 525° C.), and a high viscosity (typically about 27,000 cPs at 40° C.). The bitumen in the underground oil sand reservoir is generally intimately associated with sand or clay in a bitumen bearing zone  1 . The bitumen bearing zone  1  typically occurs below between 50 and 500 meters of over burden  2  and has a thickness between 5 and 50 meters. The gaseous contents of the bitumen bearing zone  1  are typically perlimited by an upper barrier layer  3  somewhere in the over burden  2  and a lower barrier layer  4  somewhere in the underlying zones  5 . 
       FIG. 1  will also be used to illustrate the key features of this continuous bitumen production method. Typically, purge steam  6  is injected into the bitumen bearing zone  1 , via an injection well  7 , to preheat and purge non-condensable gases, primarily nitrogen, from the bitumen bearing zone  1 . This steam flows from the injection well  7 , through the bitumen bearing zone  1  to the production well  8  and exits via the well product  9  line. The production well  8  may be a vertical pipe, or preferably, a vertical pipe with a horizontal segment underlying the bitumen production zone  1  as shown in  FIG. 1 . Production steam  10  may advantageously be used to heat the production well  8  and the region in the vicinity of the production well  8 . 
     For simplicity,  FIG. 1  considers the most straightforward case of a single injection well  7  and a single production well  8  pair for the oil sand reservoir. However, typically many injection and production well pairs are utilized in a matrix configuration to increase the rate and amount of bitumen produced from an underground oil sand reservoir. Once the purge steam  6  has displaced the non-condensable gases from the bitumen bearing zone  1 , an oxygen containing oxidant  11  is continuously injected into the bitumen bearing zone  1  via the injection well  7 . This method is applicable for bitumen production from an underground oil sand reservoir using the continuous flow of an oxidant  11  with any configuration of oxidant injection  7  and production  8  wells. The alternative ‘huff and puff’ type in situ combustion processes, that alternatively feed the oxidant and collect the product using a single well, is outside the scope of this invention. 
     This continuous in situ combustion bitumen production method can be envisioned in terms of three regions within the bitumen bearing zone  1 : the bitumen depleted zone  12 , the petroleum coke zone  13 , and the bitumen production zone  14 . The continuous in situ bitumen production process will be described in terms of these zones. 
     The bitumen depleted zone  12  can be visualized as a substantially hydrocarbon free region. The oxygen containing oxidant  11  is fed to the bitumen bearing zone  1  via the injection well  7 . The oxidant  11  flows from the injection well  7 , permeates through the depleted zone  12  substantially uneventfully until it encounters the high temperature petroleum coke zone  13 . The oxygen in the oxidant  11  rapidly reacts with excess hot petroleum coke  13  to produce primarily carbon monoxide and hydrogen. The resulting high temperature gas stream permeates the petroleum coke zone  13  and encounters bitumen in the leading edge of the bitumen production zone  14 , which initiates endothermic coking reactions that maintain a well defined petroleum coke zone  13  that progressively moves from the oxidant injection well  7  to the vertical leg of the production well  8 . The endothermic coking reactions temper the gas, thus providing an appropriate medium to heat the bitumen within the bitumen production zone  14 , decreasing its viscosity, and facilitating bitumen flow to the underlying production well  8 . Then, the fuel gas  15 , that was produced in the bitumen production zone  14 , serves as the motive flue for a gas lift within the vertical leg of the production well  8  to transport the well product  9  to a conventional gas-solid-liquid separator  16  that segregates the well product  9  stream into the fuel gas  15 , bitumen  17 , water  18 , and sand  19  product streams. 
     For convenience, safety, and process reasons, nitrogen is typically used as the primary diluent in the oxidant  11 .  FIG. 2  shows the effects of oxygen concentration and diluent type on the petroleum coke gasification temperature (left ordinate axis). The carbon dioxide diluent substantially reduces the temperature rise associated with higher oxygen concentrations via the endothermic reverse Boudouard reaction: CO 2 (g)+C(s)           2CO(g) ΔH=−172 KJ/M. Additional petroleum coke is formed when the high temperature and CO-rich gas from the petroleum coke zone  13  first contacts bitumen in the bitumen production zone  14 . The carbon dioxide diluent is more effective than nitrogen in the bitumen production zone  14  for three reasons. First, carbon dioxide can heat the bitumen production zone  14  more effectively because it has a higher heat capacity than nitrogen. Second, essentially all the chemical energy stored in the CO product from petroleum coke gasification is released as thermal energy into the bitumen production zone  14  via the exothermic Boudouard reaction: 2CO(g)         CO 2 (g)+C(s) ΔH=172 KJ/M. Third, and most importantly, carbon dioxide miscibility in bitumen substantially decreases the bitumen viscosity, which dramatically decreases the energy required for bitumen production.
       FIG. 2  also summarizes the thermal energy input requirement (right ordinate axis) for bitumen production using the leading bitumen production processes. The first point to be made is that mining has a much higher energy input requirement than any of the in situ bitumen production processes. The SAGD bitumen production process only uses steam heating to enhance bitumen production. The air in situ bitumen production process uses the combination of the heat of combustion and modest carbon dioxide partial pressure to reduce the energy input requirement by about 15% relative to the SAGD process. The carbon dioxide-oxygen combustion in situ bitumen process decreases the required thermal energy input by 65% to 82% relative to SAGD, depending on the oxidant oxygen concentration, by increasing the carbon dioxide partial pressure. Clearly, the preferred oxidant diluent is carbon dioxide. The preferred oxidant pressure and O 2  concentration ranges are 10 to 50 bar and 10 to 40 molar percent, more preferably 20 to 40 bar and 15 to 30 molar percent. 
       FIG. 3  illustrates a typical oxygen combustor and electrical power generation system that can be used to produce a CO 2  rich gas stream  38  that serves as a key constituent for an oxidant  11  with the preferred CO 2  diluent. Since a substantial portion of the carbon monoxide and hydrogen that were produced by the petroleum coke gasification reactions in the bitumen bearing zone  1  are converted to carbon dioxide and water in the bitumen production zone  14 , the gaseous hydrocarbon products, primarily methane, from the bitumen coking reactions are the primary fuel components in the fuel gas  15 . The fuel gas  15  calorific value increases from about 1.6 to about 6 MJ/Nm 3  as the oxygen content of the oxidant  11  is increased from 10 to 40 molar percent. For reference, natural gas typically has a heating value of about 40 MJ/Nm 3 . The fuel gas  15  is preheated in the O 2 -fuel steam boiler  20 . Natural gas  21  may be advantageously added to the preheated fuel gas  22  to maintain a reasonable combustion temperature when the fuel gas  15  heating value is less than about 3 MJ/Nm 3 . Recycle CO 2  rich gas  23  may be used to limit the combustion flame temperature when the fuel gas heating value is substantially greater than 3 MJ/Nm 2 . 
     The substantially pure oxygen feed  24  feed rate is set such that the oxygen content in the O 2 -fuel steam boiler  20  off-gas  25  is greater than about 1 molar percent. Substantially pure O 2  preferably has an O 2  content greater than 70 molar percent, more preferably greater than 90 molar percent, most preferably greater than 95 molar percent. The O 2 -fuel steam boiler  20  produces high pressure steam  27  (typically about 60 bar) using recycle condensate water  28  from the conventional electrical power generator  29  and boiler feed water  30 . The high pressure steam is used to produce electrical power  31  in the electrical power generator  29 , purge steam  6  to remove non-condensable gases from the bitumen bearing zone  1 , and production steam  10  to heat the production well  8  and the bitumen production zone  14  in the vicinity of the production well  8 . Typically an aqueous scrubber  32  is used to temper and remove SO 2  from the O 2 -fuel stream boiler  20  off-gas  25 . Typically an aqueous limestone slurry  33  is used as the base to remove SO 2  from the O 2 -fuel stream boiler  20  off-gas  25 , which produces an aqueous CaSO 3  slurry by-product  34 . Typically an air cooler  35  would be used to control the water content of the scrubber  32  off-gas  36 . A blower  37  provides the motive force for the CO 2  rich gas recycle  23  feed to the O 2 -fuel steam boiler  20  and the export CO 2  rich gas  38 . 
       FIG. 4  is a block flow diagram that will be used to illustrate the description of this in situ bitumen production method with carbon dioxide capture and sequestration. Block  39  represents an oil sand reservoir that is ready for bitumen production. Blocks  40  and  41  represent depleted oil sand reservoirs that are used as a CO 2  source and sink, respectively. These depleted oil sand reservoirs are used for both long-term underground CO 2  sequestration and short-term underground CO 2  storage to meet the periodic high CO 2  demand for well pair start-up.  FIG. 4  illustrates the general features of Block  39 ,  40 , and  41  with the understanding that the bitumen production zone  14  extends from the injection well  7  to the vertical member of the production well  8  in Block  39  and the bitumen depleted zone  12  extends from the injection well  7  to the vertical member of the production well  8  for the depleted oil sand reservoirs represented by Blocks  40  and  41 . 
     The initial oil sand reservoir  39  start-up step is to use purge steam  6  to remove the non-condensable gases. The purge steam is produced by the O 2  combustor &amp; power generator  42 .  FIG. 4  illustrates a typical configuration for the O 2  combustor &amp; power generator  42 . The non-condensable gases, primarily nitrogen, are purged from the oil sand reservoir for bitumen production  39  via the well product  19 , gas-liquid-solid separator  16 , and the non-condensable gas purge stream  43 . Then, the oxidant  11  feed to the oil sand reservoir for production  39  is initially produced by blending start-up CO 2  gas  44  from depleted oil sand reservoir CO 2  source  40  and any excess CO 2  rich gas  45  from the O 2  combustor and power generator  42  with substantially pure O 2    46  from a conventional cryogenic or pressure swing adsorption O 2  generator  47  to achieve the desired oxidant flow rate and O 2  content, typically in the 10 to 40 molar percent oxygen range. The oxidant flow rate is generally in the range of 1000 to 6500 Nm 3 /hr depending on the design of the well pair. Generally, some imported electrical energy  48  is required to meet the total substantially pure O 2  feed requirement  49 . The oxidant compressor  50  increases the oxidant feed  11  to the desired pressure, typically in the range of 10 to 50 bar, preferably in the 20 to 40 bar range. The oxidant  11  is injected into the bitumen bearing zone  1 , which produces the fuel gas  15 , bitumen  17 , water  18 , and sand  19  products as described previously and illustrated in  FIG. 1 . The fuel gas  15  is fed to the O 2 -fuel combustor and power generator  42  to produce electrical power  31 , purge steam  6 , production steam  10 , and CO 2  rich gas  38  as described previously and illustrated in  FIG. 3 . 
     The CO 2  sequestration compressor  51  compresses any excess CO 2  rich gas production  52  to produce a high pressure CO 2    53  for sequestration in a depleted oil sand reservoir CO 2  sink  41  at a pressure between 30 and 70 bar, depending on the quantity of CO 2  produced and the nature of the oil sand reservoir.  FIG. 5  illustrates a method to estimate the oil sand reservoir CO 2  capacity (Nm 3 /bbl bitumen produced) as a function of the oil sand reservoir sand to bitumen ratio (MT/bbl) with parameters of sequestration pressure and the CO 2  for sequestration  53  (Nm 3 /bbl bitumen produced) as a function of bitumen production operating conditions outlined in the Example. The reservoir CO 2  capacity must be a supermajority of the CO 2  produced for sequestration, preferably greater than 66%, more preferably greater than 80%, most preferably greater than or equal to 100%. If the CO 2  produced for sequestration is greater than the oil sand reservoir capacity, then the excess CO 2  produced can be sequestered in a supplemental CO 2  sequestration reservoir. 
     Example 
     The example will summarize the key operating conditions and performance indicators for the system in  FIG. 4  with oxidants  11  containing 21 molar percent O 2  with CO 2  and N 2  diluents and a 10 molar percent O 2  oxidant with a CO 2  diluent. A conventional cryogenic O 2  generator  47  produced a 95 molar percent molar oxygen substantially pure oxygen  49  feed stream with argon as the major impurity. The O 2 -fuel steam boiler  20  was operated with a 1500° C. flame temperature and produced high pressure steam at 482° C. and 61.7 bar for all cases. The natural gas  21  lower heating value was 37 MJ/Nm 3  for all cases. The production steam  10  flow rate was 200 kilograms per hour per well pair for all cases. The oxidant  11  pressure was 35 bar and flow rate was 2500 Nm 3  per hour per well pair for all cases. A number of parameters can be used to evaluate the performance of the 21% O 2  in CO 2 , 21% O 2  in N 2 , and 10% O 2  in CO 2  oxidants. For example, oxidant feed rates were 82.3, 220, and 87.5 Nm 3 /bbl, respectively, which indicates that the CO 2  diluent very effectively increases the bitumen production. The fuel gas  15  lower heating values were 3.1, 3.0, and 1.9 MJ/Nm 3 , which indicates that fuel gas heating value increases with oxidant O 2  concentration and is a weak function of the diluent type. The fuel gas  15  energy contents were 255, 660, and 140 MJ/bbl, respectively. The natural gas feed energy contents were 2, 690, and 145 MJ/bbl, respectively. The net electrical energy requirements were 6.7, −0.2, and 4.0 KW-hr/bbl, respectively. Most importantly, the CO 2  rich gas for sequestration  53  specific flow rates were 19, 380, and 12.5 Nm 3 /bbl, which indicates, based in  FIG. 5 , that sand to bitumen ratios of about 1.75 and 2.5 MT/bbl would be required to sequester all the CO 2  rich gas for sequestration  53  with the sequestration pressure equal to the operating pressure of 35 bar for the 10% and 21% O 2  in CO 2  oxidants. This sand to bitumen ratio range is within the normal range found in oil sand reservoirs. Clearly, the CO 2  rich gas for sequestration  53  specific flow rate of 380 Nm 3 /bbl for the air based in situ bitumen production process is well outside of the practical range. 
     While this invention has been described with respect to particular embodiments thereof, it is apparent that numerous other forms and modifications of the invention will be obvious to those skilled in the art. The appended claims in this invention should be construed to cover all such obvious forms and modifications which are within the true spirit and scope of the invention.

Summary:
A method for the production of a CO 2  rich stream for sequestration in depleted oil sand reservoirs. The method comprises the steps of: a) purging non-condensable gases from an oil sand reservoir with steam; b) contacting a gaseous oxidant stream comprising oxygen, carbon dioxide, and steam with bitumen in an oil reservoir; c) separating the production well product from the oil sand reservoir into bitumen, water, sand and fuel gas streams; d) producing a carbon dioxide rich gas by combustion of the said fuel gas with substantially pure oxygen; e) utilizing substantially pure oxygen and a portion of said carbon dioxide rich gas as constituents of said gaseous oxidant stream; and f) sequestering a balance of said carbon dioxide rich gas into a depleted oil said reservoir.