CA2706399A1 - Steam and flue gas injection for heavy oil and bitumen recovery - Google Patents

Abstract

A method for thermal recovery of heavy oil, bitumen and natural gas from a formation containing various hydrocarbons and an apparatus for generating a mixture of steam and flue gas, named as steamflue gas. In general, the method incorporates high temperature flue gas into a steam assisted gravity drainage (SAGD) operation to become a steamflue gas injection.
A mixture of high temperature flue gas and steam is injected into the SAGD top well within a formation to enhance recovery of heavy oil and bitumen. The high temperature flue gas is produced from the first burner burning inexpensive fuels, such as coal, used oil, scraped tire, petroleum coke and sludge containing high oil content; and the steam is generated by mixing water with the high temperature flue gas or the steam generated using a steam generator conventionally used in a SAGD recovery operation. The returning flue gas with entrained hydrocarbons from the formation is burned in the second burner as an additional fuel to preheat water or generate steam. Then the flue gas produced from the second burner is injected into the formation and acts to re-pressurize the formation which otherwise becomes depressurized when depleted of natural gas. Accordingly, environmental and economic advantages are realized with the methodology.

Description

Steam and Flue Gas Injection for Heavy Oil and Bitumen Recovery Inventors: Guoxing Gu (Edmonton, CA) Assignee: Little Moon Ventures Ltd. (Edmonton, CA) Docket No.

Field of the Invention [0001] The present invention relates to the thermal recovery of heavy oil and bitumen from a subterranean formation by making use of a steamflue gas, a mixture of steam and flue gas, injection into the formation.

Background [0002] Currently, existing bitumen and extra heavy oil reservoirs are exploited using enhanced recovery techniques. The three major types of enhanced oil recovery operations are chemical flooding (alkaline flooding or micellar-polymer flooding), miscible displacement (carbon dioxide injection, hydrocarbon injection, nitrogen injection and flue gas injection), and thermal recovery (hot water flooding, steam flooding, and in-situ combustion). The optimal application of each type depends on reservoir temperature, pressure, depth, net pay, permeability, residual oil and water saturations, porosity and fluid properties such as oil API
gravity and viscosity.

[0003] Thermal recovery is used to produce viscous, thick oils with API
gravities less than 20.
These oils cannot flow unless they are heated and their viscosity is reduced enough to allow flow toward producing wells.

[0004] During thermal recovery, oil undergoes physical and chemical changes because of the effects of the heat supplied. Physical properties such as viscosity, specific gravity and interfacial tension are altered. The chemical changes involve different reactions such as cracking, which is the destruction of carbon-carbon bonds to generate lower molecular weight compounds, and dehydrogenation, which is the rupture of carbon-hydrogen bonds.

[0005] The most common thermal technique is steam injection where heat enthalpy from the steam is transferred to the oil by condensation. This, of course, reduces the viscosity of the oil allowing gravity drainage and collection. Injection may be achieved by the well known = Cycling Steam Stimulation (CSS) = Steam Flooding (SF) = Steam Assisted Gravity Drainage (SAGD) CSS and SF generally target thicker and deeper bitumen deposits, situated more than 400 metres below surface. SAGD typically targets intermediate-depth deposits, located less than 400 metres below surface, with relatively high sand permeability.

Cycling Steam Stimulation [0006] In CSS, steam is injected at high pressure and temperature (as high as 350 C) into the oil sand formation for several weeks. Steam helps recover the resource in several ways. The heat dramatically reduces the viscosity of the oil sands and the water vapour helps to break out the bitumen from the sand that contains it. The high pressure induces fractures to be formed in the formation, through which steam can penetrate the oil sands. After a portion of the reservoir has been invaded and saturated, the steam is turned off and the reservoir is allowed to soak for several weeks. Then, the injection wells are turned into production wells. The mixture of condensed water and mobilized bitumen either flows on its own uphole to surface, or is pumped to the surface using downhole pumps activated by pumpjacks at surface. When the rate of production starts to decline, the injection-soak-production cycle is repeated. It can take between 120 days and two years to complete a single cycle. At surface, the cooling bitumen is typically mixed with diluents to reduce its viscosity and allow its transportation by pipeline.

[0007] Canada's oldest and largest in-situ CSS bitumen recovery project is Imperial Oil's Cold Lake in north eastern Alberta. Bitumen production averaged more than 24 000 cubic metres per day in 2007 from approximately 4 000 wells. This was approximately 40% of Canada's total in-situ production, or about 5% of total Canadian oil production.

Steam Flooding [0008] SF is also a steam-based process. It involves continuous injection of steam into vertical injector wells. The steam mobilizes the heated bitumen and drives it towards production wells. However, recovery efficiencies are generally poor due to gravity override of the steam over the bitumen, hence a significant amounts of the oil is bypassed. With bitumen recovery typically less than 20% even in the best bitumen deposits, SF is not a common bitumen recovery process.

Steam Assisted Gravity Drainage (SAGD) [0009] SAGD typically relies on two horizontal wells drilled near the base of the reservoir formation with a vertical separation of several metres. Steam is injected into the reservoir through the upper well. As the steam rises and condenses, it heats up the bitumen, reducing its viscosity. A "heat chamber" is created, which allows the hot bitumen and condensed steam (water) to drain by gravity into the lower producing well. The mobile bitumen then flows or is pumped up to surface.

[0010] Although SAGD is becoming widely employed, it is not without several detriments regarding efficiency. An area which presents significant costs is the fuel to drive the steam generators to produce steam for injection. The most desirable fuel is natural gas, but the expense greatly reduces the overall efficiency and this problem is compounded with the fact that green house gases (GHG) are liberated in varied amounts during operation of the steam generators using all types of hydrocarbon fuels. As an example, approximately 8,000 to 15,000 Tones daily of carbon dioxide is generated to produce injection steam and produce 100,000 barrels of heavy oil or bitumen per day.

[0011] As noted briefly above, another factor affecting SAGD is the limitation in recovery efficiency.

New Technologies [0012] New technologies continue to improve project economics and reduce environmental impacts from bitumen recovery operations. Examples of these advanced technologies include:
= Solvent-assisted processes - which reduces bitumen viscosity by adding solvent to the reservoir formation.
= Expanding solvent-SAGD - a steam-based hybrid process involving the addition of a solvent or mixture of solvents to the steam. Advantages include further reduction of bitumen viscosity and reduced steam utilization.

[0013] In-situ combustion is also a potential candidate for improving project economics and significantly reducing environmental impacts. The most promising is Toe-to-Heal-Air-Injection (THAI) disclosed in US 6,167,966, US 2005/0082057, US 2006/0207762 and US
2008/0066907. This technique consists of two wells: a horizontal producer situated at the bottom of the producing formation, and a vertical air injector at the toe of the producer.
Initially, the formation near the vertical injector is super-heated to the spontaneous ignition temperature. Then air injection is started using the vertical well, resulting in in-situ combustion. The combustion reduces the viscosity of the surrounding bitumen and allows it to drain into the producer. The combustion chamber progresses along the horizontal producer, starting from the toe towards the heel of the producer. The produced CO2 remains in the reservoir. This method is currently being tested by Petrobank at Whitesands.
Bitumen production rates are in the range of 130 cubic metres per day per well.
Petrobank is planning a commercial project with an initial rate of 16,000 cubic metres per day of bitumen production.

[0014] In an attempt to ameliorate some of the limitations noted, the use of alternate fuels other than natural gas has been proposed to at least reduce the ever increasingly impact of natural gas. An example of a suitable fuel for use in a SAGD operation is discussed in US
6,530,965, issued to Warchol on Mar. 11, 2003. The document teaches the formation of pre-dispersed residuum in an aqueous matrix which is burnable as an alternative fuel.
US 7,341,102 teaches a variety of methods for incorporate a series of existing, but previously uncombined technologies for thermal recovery of natural gas and bitumen from a formation containing the latter. A modified flue gas from the steam generators conventionally used in a SAGD recovery operation is injected into the formation to enhance recovery of natural gas and bitumen. The injection of the flue gas conveniently is disposed of and further acts to repressurize the formation which otherwise becomes depressurized when depleted of natural gas. Accordingly, environmental and economic advantages are realized with the methodology.

[0015] The present invention collates most desirable features and advantages of carbon dioxide injection, steam injection and equivalent Toe-to-Heal-Air-Injection into a SAGD
operation, which is a high energy efficient, high yield green environmentally friendly process.
Limitation of the existing technologies [0016] Considering the problems with existing technologies, it remains desirable to have a method of enhancing efficiency in a SAGD operation, reducing the formation of excessive amounts of GHG and lowering costs by providing an alternate fuel with the thermal performance of natural gas.

[0017] The present invention collates most desirable features and advantages of carbon dioxide injection, steam injection and equivalent Toe-to-Heal-Air-Injection into a SAGD
operation, which is a high energy efficient, high yield green environmentally friendly process.
Definition:

[0018] 1. Flue gas is defined as a mixture of all gases after a fuel is burned. It may contain CO2, CO, NOR, SO,, N2 and H2O (vapor).

[0019] 2. Steamflue gas is defined as a mixture of added steam and flue gas in any weight ratio.

Summary of The Invention [0020] One object of the present invention is to provide an improved thermal recovery process with enhanced efficiency.

[0021] A further object of the embodiment of the present invention is to provide a method and apparatus for generating a steamflue gas, a mixture of steam and flue gas, by mixing high temperature flue gas and pressurized water.

[0022] A further object of the embodiment is to provide a method for combining desirable features and advantages of carbon dioxide injection, flue gas injection, steam injection and equivalent Toe-to-Heal-Air-Injection into a SAGD operation, which is a high energy efficient, high yield green environmentally friendly process [0023] A further object of the embodiment is to provide a method for recovering heavy oil and bitumen from a subterranean formation containing heavy oil and bitumen.

[0024] A further object of the embodiment of the present invention is to provide a method for recovering gas, heavy oil and bitumen from at least one of a steam assisted gravity drainage formation containing gas over heavy oil and bitumen within the volume of the formation and/or from a geographically proximate formation.

[0025] Having thus general descriptions of the present invention, reference will now be made to the accompanying drawings illustrating a preferred embodiment.

Brief Description Of The Drawings [0026] FIG. 1 is a schematic illustration of the generic methodology according to the embodiment;

[0027] FIG. 2 is a schematic illustration of the steamflue gas generation unit;

[0028] FIG. 3 is a generic illustration of the burner for high temperature flue gas generation;

[0029] FIG. 4 is a sectional illustration of the mixing unit for mixing the high temperature flue gas and pressurized water to produce over heated water.

Detailed Description of Preferred Embodiment [0030] A method for recovering oil (heavy oil and bitumen) from a subterranean formation containing said oil or recovering oil (heavy oil and bitumen) and gas from at least one of a steam assisted gravity drainage formation containing gas over said oil within the volume of said formation and from a geographically proximate formation, are described below with reference to Figure 1 comprising:

a) two burners; one burner for high temperature flue gas production and another for water preheating and burning off hydrocarbons present in recycled gases;

b) a steamflue gas generation mean for generating and then injecting said steamflue gas into said formation;

c) a horizontal well pair for steamflue gas injection and oil production and a vertical well for entrained volatile oil recovery;

d) a flue gas injection well and a natural gas production well;
e) a flue gas circulation and a flue gas recirculation circuits;

[0031] Detailed descriptions of the process of the present invention are as follows:

[0032] With reference to FIG. 1, showing a schematic illustration of the generic methodology according to the embodiment, the high temperature flue gas produced from burner 1 is channeled via conduct 2 and combined with recycled process water (in water pipe 3) in the steamflue gas generation unit 4. The high temperature flue gas may contain numerous gaseous compounds including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides, hydrogen, sulfur dioxide, and water vapor as well. After mixing, the steamflue gas is generated and then injected via line 5 into the injection well 6 located in a SAGD formation 10 containing oil and gas. As is well known, this technique involves the use of steam to assist in reducing the viscosity of viscous hydrocarbons to facilitate mobility.

[0033] Due to steam condensation in the injection well 6, the injected steamflue gas splits into two parts, condensed steam (water) and uncondensed gases. The water flows into the bottom production well 7 and is withdrawn with oil in the production well via line 8 to the oil treatment unit 20; the uncondensed gases containing entrained hydrocarbons in the injection well 6 is withdrawn via the recovery well 9 and sent via a control valve 11 and line 12 to a condenser 30 for gas/liquid separation.

[0034] The produced fluid containing oil is then subjected to an oil treatment operation 20 where the oil is processed for the removal of entrained water to produce a saleable product.
Produced water 21 is further treated in a suitable water treatment unit 22 to remove bitumen, hardness compounds, silica and any other undesirable compounds making the water suitable of boiler feed water 23. Any suitable water treatment operations may be employed to achieve the desired result. Boiler feed water 23 may then be preheated in a water preheating unit 24 then recycled into the steamflue gas generation unit 4 via water line 3 for steamflue gas production, thus reducing water demands in the process to augment efficiency.

[0035] The produced gases containing entrained hydrocarbons are then subject to condensation 30 for gas/liquid separation where heavy components and water are condensed.
Any suitable condenser may be used to achieve the desired result. However, it is preferable to use an impingement condensation system with associated air cooling system, which is detailed in US provisional application US 61/094,190. The fluid 31 evolved from the condensation operation is combined into production line 8 for treatments. The remaining uncondensed gases (NCGs) 32 still containing light hydrocarbons are recycled to a burner 33 as additional fuel. The burner 33 is similar to burner 1 and will be described later. The hot flue gas 34 from the burner 33 is supplied to a water preheating unit, which can be any type of commercially available boilers being able to hook up with the burner's flue gas channel after minor modification.

[0036] After heat exchange in the water treatment unit 24, the flue gas 35 is treated or modified in a treatment operation 36 prior to injection into a formation. The treatment operation is similar to the operation disclosed in US 7,341,102. Further to this, water 38 evolved from the flue gas treatment operation may be circulated at 22, also to augment efficiency.

[0037] This flue gas 35 may contain numerous gaseous compounds including carbon dioxide, carbon monoxide, nitrogen, nitrogen oxides, hydrogen, sulfur dioxide, and water vapor as well. At excess oxygen burning conditions, where oxygen levels are present in the flue gas 35, then the flue gas 35 will primarily contain carbon dioxide, nitrogen and water vapor. The treated injection gas 37 is injected into gas and heavy oil formation(s) generically denoted by numeral 10, shown in the example as a SAGD (steam assisted gravity drainage) formation. As is well known, this technique involves the use of steam to assist in reducing the viscosity of viscous hydrocarbons to facilitate mobility. These formations also contain natural gas, heavy oil, bitumen.

[0038] The gas in the formation 10 is now made recoverable in an efficient manner with injection of the treated flue gas 37. The combination of these operations has resulted in the success of the methodology of the present invention. Advantageously, the techniques set forth herein can be applied not only to gas over heavy oil and bitumen formations, but also geographically proximate formations. As a non limiting example, laterally or vertically displaced formations can be exploited as well. The benefits of the instant technology also accrue for abandoned SAGD chambers or for blow down where flue gas can be injected to not only maintain heavy oil recovery but also to displace the heavy oil.

[0039] Natural gas 13 displaced from formation 10 is collected and may be subjected to additional unit operations or a portion may be circulated into the system as fuel for steamflue gas generation or water preheating. This latter step is not shown in FIG. 1, but is well within the purview of one skilled.

[0040] Having broadly discussed the overall process, numerous advantages attributable to the process are shown. These include:

i) high energy efficiency with low cost;

ii) an efficient and environmentally safe disposal of harmful flue gas;

iii) improved gas recovery from the formation;

iv) enhanced thermal recovery operation to produce more oil per unit steam;
v) carbon dioxide sequestering to reduce GHG emissions;

vi) volumetric replacement within the formation;
vii) and any combination of these features.

[0041] Referring now to FIG. 2, showing a schematic illustration of the steamflue gas generation unit 4, the water 3 from water preheating unit 24 is pressurized by a pump 40a prior to mixing in a mixing unit 42 with the high temperature flue gas 2 produced from the burner 1. After mixing, the pressurized water with entrained flue gas becomes an overheated multiphase fluid 43. The overheated multiphase fluid 43 then splits its phases in a phase separator 50 into a gas phase 51, named as the steamflue gas 5, and a water phase 52. The steamflue gas is ready for injection into a formation containing heavy oil and bitumen or a formation containing gas over heavy oil and bitumen within its formation. The water 52 is released via a control valve 53 and a pump 40b into line 54 then circulated after combining into water line 3 for next cycle steamflue gas generation.

[0042] Referring now to FIG. 3, showing a generic illustration of the burner for high temperature flue gas generation, the burner has a fuel gasification chamber 60 where fuel 61 is gasified in an insufficient oxygen (air 62) environment; and a combustion chamber 66 where the gasified fuel or gas oil is burned completely in a sufficient oxygen (air 65) environment to produce the high temperature flue gas 2. Prior to combustion 66, for the burner 1 as show in Fig. 1, the gasified fuel or gas oil exit from the gasification chamber via channel 63 and enter a turbo section 64 to mix with additional air 65 thoroughly; for the burner 33 as shown in Fig. 1, the burner 33 also receives the recycled hydrocarbons 32 from the condenser 30 as additional fuel. Ash 67 is discharged from the bottom of the gasification unit.

[0043] Referring now to FIG. 4, showing a sectional illustration of the mixing unit for mixing the high temperature flue gas and pressurized water to produce over heated water, the pressurized water in line 41 passes multiple orifice plates 70a, 70b and 70c with holes 71a, 7lb and 7lc one for each and create multiple vena contracta points 72a, 72b and 72c at which the high temperature flue gas can be sucked into the water stream via multiple channels 73a, 73b and 73c. The multiple suction points are spaced along the water line 41 in such a way that the highest vacuum pressure can be achieved at each point. The orifice sizes and vena contracta points are dependent upon the injection pressure and the composition of the steamflue gas required by injection/production operation.

[0044] In Fig. 1, there is a flue gas circulation and a flue gas recirculation circuits. The flue gas circulation circuit includes the steamflue gas generation unit 4, the steamflue gas injection well 6 and a volatile recovery well 9; the flue gas recirculation circuit includes a condensation unit 30, a burner 33, a water preheating unit 24, a flue gas treatment unit 36 and a injection line 37 for sequestering of green house gas (GHG) into said formation.

Claims [0045] Embodiments of the invention may be described as follows:

Claims (25)

1. A method for recovering oil (heavy and bitumen) from a subterranean formation containing said oil or recovering oil (heavy and bitumen) and gas from at least one of a steam assisted gravity drainage formation containing gas over said oil within the volume of said formation and from a geographically proximate formation, comprising:

providing a steamflue gas generation mean for injecting said steamflue gas into said formation;

providing a high temperature flue gas produced by burning a variety of inexpensive fuels in a burner;

providing a mixing mean for mixing a low temperature pressurized water and a high temperature flue gas to produce an intermediate temperature said steamflue gas, and injecting said steamflue gas into said formation;

providing a flue gas circulation and a flue gas recirculation circuits;

2. The method as set forth in claim 1, wherein said flue gas circulation circuit includes said steamflue gas generation unit, a steamflue gas injection well and a volatile recovery well;
said flue gas recirculation circuit includes a condensation unit for gas/liquid separation, a burner, a water preheating unit, a flue gas treatment unit and a sequestering of green house gas (GHG) into said formation.

3. The method as set forth in claim 1, wherein said steamflue gas generation mean comprises said burner to produce said high temperature flue gas, a water pump to produce a pressurized water, a mixing mean to mix said high temperature flue gas and said low temperature pressurized water so as to produce a over heated mixture of water and flue gas, and a gas/liquid phase separation unit to separate liquid phase (water) from gas phase (steam + flue gas), named as a steamflue gas for injection into a formation.

4. The method as set forth in claim 1, wherein said high temperature flue gas is produced from said burner by burning a variety of inexpensive fuels, such as coal, used oil, scraped tire, petroleum coke, petroleum sludge containing high oil content, in a burner described in detail in US provisional application US 61/094,190.

5. The method as set forth in claims 1 and 3, wherein said burner compromises:

a gasification chamber wherein said inexpensive fuel is burned into a gas oil under insufficient oxygen (air) environment;

a combustion chamber wherein said gas oil is burned in an optimized oxygen (air) environment to produce said high temperature flue gas wherein heat is carried;

a turbo section between said gasification chamber and said combustion chamber wherein said gas oil and oxygen (air) are mixed thoroughly for high efficiency combustion;

and a recycled fuel inlet located at the end of said turbo section and in the beginning of said combustion chamber for receiving recycled gases containing hydrocarbons.

6. The method as set forth in claim 3, wherein said high temperature flue gas has a temperature range of 600 - 1500 °C; said low temperature pressurized water has a temperature range of 10 - 200 °C; said over heated mixture of water and flue gas has a temperature range of 200 - 600 °C.

7. The method as set forth in claim 3, wherein said over heated mixture of water and flue gas separates its phases in said gas/liquid phase separation unit to separate liquid phase (water) from gas phase (steam + flue gas), named as steamflue gas.

8. The method as set forth in claim 3, wherein said liquid phase (water) is released from the bottom of said gas/liquid phase separation unit and is circulated back into the steamflue gas generation mean via a control valve and a circulation pump then merges into the pressurized water for further mixing and heating, and said steamflue gas is released from top of said gas/liquid phase separation unit for said steamflue gas injection.

9. The method as set forth in claim 3, wherein said steamflue gas contain 0 -100% flue gas depending on injection requirement at different operation stages; the two extreme cases of 0 % and 100% flue gas mean 100% steam and 100% flue gas, respectively.

10. The method as set forth in claim 3, wherein said mixing mean comprises a water pipe line with multiple (at least one) orifice plates to create multiple vena contracta points along the pipe where said high temperature flue gas can be injected into or sucked into said pressurized water stream and turn said pressurized water into said over heated mixture of water and flue gas.

11. The method as set forth in claim 10, wherein said multiple vena contracta points are optimum spaced in such a way that maximum suction can be achieved at each said vena contracta point.

12. The method as set forth in claim 2, wherein said steamflue gas injection well is a horizontal injection well with configuration similar to the well-known SAGD
horizontal injection well.

13. The method as set forth in claim 2, wherein said volatile recovery well is a vertical well and the end is apart from the toe of said horizontal injection well. The distance between the ends of said vertical and said horizontal wells is in a range of 2 - 30 meters depending on the permeability of said formation.

14. The method as set forth in claim 13, wherein said volatile recovery well has a valve at its surface part to control the fluid flow rate and said well pressure.

15. The method as set forth in claim 2, wherein said condensation unit for gas/liquid separation is a cooling system, preferably the cooling system described in detail in US
provisional application US 61/094,190. The cooling system condenses moisture into water and relatively heavier volatile into liquid oil, leaving non condensable gases that contain light hydrocarbons going to said burner as additional fuel. The condensed liquid is released to an oil treatment unit.

16. The method as set forth in claim 15, wherein said condensed liquid (water and oil) merges into produced liquid from a corresponding SAGD production well for oil/water separation in an oil treatment unit, in which oil is separated from water. Then water goes to a water treatment unit to produce clean recycle water or boiler feed water.

17. The method as set forth in claims 2 and 16, wherein said clean recycle water or boiler feed water is preheated in said water preheating unit for the next cycle of said steamflue gas generation.

18. The method as set forth in claim 2, wherein said water preheating unit comprises a regular boiler that receives hot exhaust as heat from said burner.

19 19. The method as set forth in claims 2 and 18, wherein said burner bums said inexpensive fuels and said non condensable gases as additional fuel from said condensation unit for gas/liquid separation.

20. The method as set forth in claims 2 and 18, wherein said hot exhaust releases its heat in said water preheating unit then is purified in said flue gas treatment unit.

21. The method as set forth in claim 2, wherein said flue gas treatment unit provides removal of by-product gas includes at least one of hydrogen, carbon monoxide, nitrogen, nitrogen oxides, sulfur oxides, and carbon dioxide.

22. The method as set forth in claim 2, wherein said flue gas treatment unit comprises at least one of the unit operations including departiculation, quenching, compression and dehydration.

23. The method as set forth in claim 20, where after purification, the said exhaust or flue gas is injected to said subterranean formation for re-pressurizing said formation and releasing natural gas within said formation.

24. The method as set forth in claim 23, wherein heavy oil is displaced from said formation during re-pressurization.

25. The method as set forth in claim 2, wherein said water preheating unit can also provide low temperature steam for mixing with said high temperature flue gas in said steamflue gas generation unit to produce intermediate temperature steamflue gas for injection.