CA2824168A1 - Process for the recovery of heavy oil and bitumen using in-situ combustion - Google Patents
Process for the recovery of heavy oil and bitumen using in-situ combustion Download PDFInfo
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- CA2824168A1 CA2824168A1 CA2824168A CA2824168A CA2824168A1 CA 2824168 A1 CA2824168 A1 CA 2824168A1 CA 2824168 A CA2824168 A CA 2824168A CA 2824168 A CA2824168 A CA 2824168A CA 2824168 A1 CA2824168 A1 CA 2824168A1
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- 238000002485 combustion reaction Methods 0.000 title claims abstract description 85
- 238000000034 method Methods 0.000 title claims abstract description 52
- 238000011084 recovery Methods 0.000 title claims abstract description 23
- 238000011065 in-situ storage Methods 0.000 title claims abstract description 18
- 239000010426 asphalt Substances 0.000 title description 12
- 230000008569 process Effects 0.000 title description 11
- 239000000295 fuel oil Substances 0.000 title description 2
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 106
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 106
- 238000002347 injection Methods 0.000 claims abstract description 97
- 239000007924 injection Substances 0.000 claims abstract description 97
- 238000004519 manufacturing process Methods 0.000 claims abstract description 71
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 63
- 239000007789 gas Substances 0.000 claims abstract description 58
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 claims abstract description 57
- 239000001301 oxygen Substances 0.000 claims abstract description 57
- 229910052760 oxygen Inorganic materials 0.000 claims abstract description 57
- 239000003546 flue gas Substances 0.000 claims abstract description 20
- 239000000203 mixture Substances 0.000 claims description 19
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 13
- 238000010438 heat treatment Methods 0.000 claims description 5
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims description 3
- 239000008186 active pharmaceutical agent Substances 0.000 claims 1
- 230000015572 biosynthetic process Effects 0.000 description 28
- 239000003921 oil Substances 0.000 description 24
- 230000005484 gravity Effects 0.000 description 17
- 230000000694 effects Effects 0.000 description 11
- 238000010796 Steam-assisted gravity drainage Methods 0.000 description 7
- 239000007788 liquid Substances 0.000 description 7
- 230000008901 benefit Effects 0.000 description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 239000000567 combustion gas Substances 0.000 description 4
- 230000009969 flowable effect Effects 0.000 description 4
- 230000006872 improvement Effects 0.000 description 4
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 3
- 239000005864 Sulphur Substances 0.000 description 3
- 239000003085 diluting agent Substances 0.000 description 3
- 229910052751 metal Inorganic materials 0.000 description 3
- 239000002184 metal Substances 0.000 description 3
- 150000002739 metals Chemical class 0.000 description 3
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 2
- 238000003491 array Methods 0.000 description 2
- -1 bitumen Chemical class 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 230000002349 favourable effect Effects 0.000 description 2
- 239000012530 fluid Substances 0.000 description 2
- 239000005431 greenhouse gas Substances 0.000 description 2
- 125000004435 hydrogen atom Chemical group [H]* 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- 239000003027 oil sand Substances 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 238000010794 Cyclic Steam Stimulation Methods 0.000 description 1
- MYMOFIZGZYHOMD-UHFFFAOYSA-N Dioxygen Chemical compound O=O MYMOFIZGZYHOMD-UHFFFAOYSA-N 0.000 description 1
- 235000015076 Shorea robusta Nutrition 0.000 description 1
- 244000166071 Shorea robusta Species 0.000 description 1
- 238000009825 accumulation Methods 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 125000004432 carbon atom Chemical group C* 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000000571 coke Substances 0.000 description 1
- 238000004939 coking Methods 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 238000007796 conventional method Methods 0.000 description 1
- 239000013256 coordination polymer Substances 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 229910001882 dioxygen Inorganic materials 0.000 description 1
- 238000007598 dipping method Methods 0.000 description 1
- 230000020169 heat generation Effects 0.000 description 1
- 239000012535 impurity Substances 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- 230000001483 mobilizing effect Effects 0.000 description 1
- 239000003345 natural gas Substances 0.000 description 1
- 229910052759 nickel Inorganic materials 0.000 description 1
- 238000005457 optimization Methods 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000007670 refining Methods 0.000 description 1
- 230000000717 retained effect Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 239000011269 tar Substances 0.000 description 1
- 238000004227 thermal cracking Methods 0.000 description 1
- 229910052720 vanadium Inorganic materials 0.000 description 1
- LEONUFNNVUYDNQ-UHFFFAOYSA-N vanadium atom Chemical compound [V] LEONUFNNVUYDNQ-UHFFFAOYSA-N 0.000 description 1
- 238000009834 vaporization Methods 0.000 description 1
- 230000008016 vaporization Effects 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/243—Combustion in situ
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimising the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimising the spacing of wells comprising at least one inclined or horizontal well
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
A well arrangement suitable for recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir (1), said well arrangement comprising: a vertical injection well (2) extending into the upper portion of said reservoir suitable for the injection of oxygen-rich gas into said reservoir; a horizontal oil production well (6), positioned in said reservoir (1) in a position below the lower end of said injection well (2) and substantially aligned with it; and a plurality of vertical vent wells (3) for removal of flue gases, said vertical vent wells (3) extending into the upper portion of said reservoir and substantially aligned along the line of said horizontal production well (7); as well as a method for recovering hydrocarbons from a subterranean reservoir comprising providing a subterranean reservoir with at least one well arrangement in accordance with the present invention, performing in situ combustion using said well arrangement and recovering mobilised hydrocarbon from the horizontal production well.
Description
Process for the Recovery of Heavy Oil and Bitumen Using in-situ Combustion Field of Invention The present invention provides a well arrangement suitable for the recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir having a toe end and a heel end, said well arrangement comprising a substantially vertical injection well, a substantially horizontal oil production well, and a plurality of substantially vertical vent wells for removal of flue gases extending into the upper portion of the reservoir and substantially aligned along the line of said horizontal production well.
The invention also provides a subterranean reservoir comprising a plurality of the well arrangements and a method for recovering hydrocarbons from the subterranean reservoir.
Background of the Invention Heavy hydrocarbons, e.g. bitumen, represent a huge natural source of the world's total potential reserves of oil. Present estimates place the quantity of heavy hydrocarbon reserves at several trillion barrels, more than 5 times the known amount of the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because heavy hydrocarbons are generally difficult to recover by conventional recovery processes and thus have not been exploited to the same extent as non-heavy hydrocarbons.
Heavy hydrocarbons possess very high viscosities and low API (American Petroleum Institute) gravities which makes them difficult, if not impossible, to pump in their native state.
Additionally, heavy hydrocarbons are characterised by high levels of unwanted compounds such as asphaltenes, trace metals and sulphur that need to be processed appropriately during recovery and/or refining.
Some methods have been developed to extract and process heavy hydrocarbon mixtures. The method that is used most often commercially today for heavy hydrocarbon recovery from subterranean reservoirs is steam assisted gravity drainage (SAGD). In this method two horizontal wells are drilled approximately five meters apart then steam is injected into the reservoir through the upper wellbore permeating the oil sand. Steam softens the heavy hydrocarbon (e.g. bitumen) and enables it to flow out of the reservoir and into the lower well. From there it is lifted to the surface facilities.
Significant improvements have been made in SAGD processes in recent years, and further optimizations continue to be driven by cost and environmental issues.
These improvements include more efficient methods for steam generation and a general reduction in the steam to bitumen ratio. Both of these improvements are aimed at reducing the amount of steam that needs to be produced which is an energy consuming process that also generates vast amounts of CO2. Another recent development has been the injection of about 10% solvents (sometimes called diluents) with the steam. The idea of this improvement is that the diluent condenses and mixes into the hydrocarbon in the formation and thereby decreases its viscosity and increases its API gravity and thus enhances its recovery.
Nevertheless the SAGD process still suffers from inherent drawbacks. These include:
(i) the use of natural gas for steam generation causes high CO2 emissions (ii) diluent must still be added to transport the recovered hydrocarbon to refineries and then separated therefrom. The latter causes CO2 emissions (iii) asphaltenes are present in the recovered hydrocarbon and their removal at refineries causes yet further CO2 emissions.
Overall the SAGD process leads to the production of vast amounts of CO2, whereas it has already been recognised in the energy industry that CO2 emissions must be managed better. The concentration of CO2 in the Earth's atmosphere has already risen from about 280 to 370 parts per million since the industrial revolution and if current trends are not changed may reach at least twice the preindustrial level by 2100. The possible environmental impact of such a change is well documented.
More recently a number of in situ combustion bitumen recovery processes have been developed and a few of these are in the pilot plant phase. In these methods the injection and production wells are only preheated using steam. Once the oil sands reservoir has been heated to a sufficient ignition temperature, air is injected into the injection wells and ignited to ultimately form a combustion front driving the bitumen recovery (the so-called Combustion Override Split-production Horizontal well process ¨
COSH). Hot combustion gases contact the bitumen ahead of the combustion zone and heat the bitumen to temperatures greater than about 300 to 400 C. An example of such a process is described in US 5,456,315.
In the method disclosed in US 5,456,315 a row of vertical injection wells is completed in the upper part of the reservoir, at least one gas production well, spaced laterally from the row of injection wells, is also provided and a horizontal production well is positioned below the injection interval. Oxygen-containing gas, typically air, is injected through each injection well and ignites. Initially a discrete combustion chamber exists around the base of each injection well but as combustion proceeds a common combustion chamber forms between each of the injection wells. The combustion zone or area has fronts comprising hot gases that serve to heat up hydrocarbon in their vicinity. This results in the production of heated heavy hydrocarbon of lower viscosity than the native hydrocarbon (the "upgraded hydrocarbons") that drains downwardly through the chamber under the influence of gravity. Thus hydrocarbon is produced from the horizontal production well lying below the injection interval. The gases produced from the in situ combustion flow through the reservoir toward the gas production wells. The gas production wells are spaced laterally from the row of injection wells as well as the production well.
However, there are problems with the COSH technique. The most significant of these are problems with control of propagation and the large number of wells that is needed due to the fact that the vent wells are located between lines of gas injector wells.
US2009/0321073 discloses a method for recovering hydrocarbon using in situ combustion wherein the combustion products are more efficiently removed from the combustion zone. In the method disclosed in US'073 oxygen is injected via an injection well to the bottom of the reservoir and flows to the combustion front. Heated oil drains to the reservoir floor and is withdrawn at a rate such that the horizontal well is liquid full throughout the burned out zone. Hot combustion gases are withdrawn from a region near the reservoir ceiling via a concentric well that may be concentric to the injection well, i.e. surround the injection well. US'073 teaches that the horizontal production well preferably defines a heel and a toe, with the heel being proximate to the injection well. As a result, the combustion front in US'073 advances from the heel towards the toe.
Nevertheless there is still a need for an improved in situ combustion technique for the recovery of hydrocarbons from a subterranean reservoir which substantially reduces the number of wells that need to be drilled, improves yield rates and allows better control of propagation and sweep of the combustion front.
The invention also provides a subterranean reservoir comprising a plurality of the well arrangements and a method for recovering hydrocarbons from the subterranean reservoir.
Background of the Invention Heavy hydrocarbons, e.g. bitumen, represent a huge natural source of the world's total potential reserves of oil. Present estimates place the quantity of heavy hydrocarbon reserves at several trillion barrels, more than 5 times the known amount of the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because heavy hydrocarbons are generally difficult to recover by conventional recovery processes and thus have not been exploited to the same extent as non-heavy hydrocarbons.
Heavy hydrocarbons possess very high viscosities and low API (American Petroleum Institute) gravities which makes them difficult, if not impossible, to pump in their native state.
Additionally, heavy hydrocarbons are characterised by high levels of unwanted compounds such as asphaltenes, trace metals and sulphur that need to be processed appropriately during recovery and/or refining.
Some methods have been developed to extract and process heavy hydrocarbon mixtures. The method that is used most often commercially today for heavy hydrocarbon recovery from subterranean reservoirs is steam assisted gravity drainage (SAGD). In this method two horizontal wells are drilled approximately five meters apart then steam is injected into the reservoir through the upper wellbore permeating the oil sand. Steam softens the heavy hydrocarbon (e.g. bitumen) and enables it to flow out of the reservoir and into the lower well. From there it is lifted to the surface facilities.
Significant improvements have been made in SAGD processes in recent years, and further optimizations continue to be driven by cost and environmental issues.
These improvements include more efficient methods for steam generation and a general reduction in the steam to bitumen ratio. Both of these improvements are aimed at reducing the amount of steam that needs to be produced which is an energy consuming process that also generates vast amounts of CO2. Another recent development has been the injection of about 10% solvents (sometimes called diluents) with the steam. The idea of this improvement is that the diluent condenses and mixes into the hydrocarbon in the formation and thereby decreases its viscosity and increases its API gravity and thus enhances its recovery.
Nevertheless the SAGD process still suffers from inherent drawbacks. These include:
(i) the use of natural gas for steam generation causes high CO2 emissions (ii) diluent must still be added to transport the recovered hydrocarbon to refineries and then separated therefrom. The latter causes CO2 emissions (iii) asphaltenes are present in the recovered hydrocarbon and their removal at refineries causes yet further CO2 emissions.
Overall the SAGD process leads to the production of vast amounts of CO2, whereas it has already been recognised in the energy industry that CO2 emissions must be managed better. The concentration of CO2 in the Earth's atmosphere has already risen from about 280 to 370 parts per million since the industrial revolution and if current trends are not changed may reach at least twice the preindustrial level by 2100. The possible environmental impact of such a change is well documented.
More recently a number of in situ combustion bitumen recovery processes have been developed and a few of these are in the pilot plant phase. In these methods the injection and production wells are only preheated using steam. Once the oil sands reservoir has been heated to a sufficient ignition temperature, air is injected into the injection wells and ignited to ultimately form a combustion front driving the bitumen recovery (the so-called Combustion Override Split-production Horizontal well process ¨
COSH). Hot combustion gases contact the bitumen ahead of the combustion zone and heat the bitumen to temperatures greater than about 300 to 400 C. An example of such a process is described in US 5,456,315.
In the method disclosed in US 5,456,315 a row of vertical injection wells is completed in the upper part of the reservoir, at least one gas production well, spaced laterally from the row of injection wells, is also provided and a horizontal production well is positioned below the injection interval. Oxygen-containing gas, typically air, is injected through each injection well and ignites. Initially a discrete combustion chamber exists around the base of each injection well but as combustion proceeds a common combustion chamber forms between each of the injection wells. The combustion zone or area has fronts comprising hot gases that serve to heat up hydrocarbon in their vicinity. This results in the production of heated heavy hydrocarbon of lower viscosity than the native hydrocarbon (the "upgraded hydrocarbons") that drains downwardly through the chamber under the influence of gravity. Thus hydrocarbon is produced from the horizontal production well lying below the injection interval. The gases produced from the in situ combustion flow through the reservoir toward the gas production wells. The gas production wells are spaced laterally from the row of injection wells as well as the production well.
However, there are problems with the COSH technique. The most significant of these are problems with control of propagation and the large number of wells that is needed due to the fact that the vent wells are located between lines of gas injector wells.
US2009/0321073 discloses a method for recovering hydrocarbon using in situ combustion wherein the combustion products are more efficiently removed from the combustion zone. In the method disclosed in US'073 oxygen is injected via an injection well to the bottom of the reservoir and flows to the combustion front. Heated oil drains to the reservoir floor and is withdrawn at a rate such that the horizontal well is liquid full throughout the burned out zone. Hot combustion gases are withdrawn from a region near the reservoir ceiling via a concentric well that may be concentric to the injection well, i.e. surround the injection well. US'073 teaches that the horizontal production well preferably defines a heel and a toe, with the heel being proximate to the injection well. As a result, the combustion front in US'073 advances from the heel towards the toe.
Nevertheless there is still a need for an improved in situ combustion technique for the recovery of hydrocarbons from a subterranean reservoir which substantially reduces the number of wells that need to be drilled, improves yield rates and allows better control of propagation and sweep of the combustion front.
Summary of the Invention The present invention provides a well arrangement suitable for the recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir the configuration of which is such that there is a maximisation of both combustion and gravity drives, with efficient production of both the mobilised liquids and the combustion flue gases. Furthermore, the number of wells that need to be drilled is minimised.
Thus, in a first aspect of the present invention there is provided a well arrangement suitable for the recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir having a toe end and a heel end, said well arrangement comprising:
(i) a substantially vertical injection well extending into the upper portion of said reservoir suitable for the injection of oxygen-rich gas into said reservoir;
(ii) a substantially horizontal oil production well, positioned in said reservoir in a position below the lower end of said vertical injection well and substantially aligned with it; and (iii) a plurality of substantially vertical vent wells for removal of flue gases, said substantially vertical vent wells extending into the upper portion of said reservoir and substantially aligned along the line of said substantially horizontal production well.
In a second aspect of the present invention there is provided a method for recovering hydrocarbons from a subterranean reservoir comprising providing a subterranean reservoir with at least one well arrangement according to the first aspect of the present invention and carrying out the following steps:
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
(ii) combusting said oxygen rich gas in said hydrocarbon reservoir thereby heating, upgrading and reducing the viscosity of said hydrocarbon mixture;
(iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
Thus, in a first aspect of the present invention there is provided a well arrangement suitable for the recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir having a toe end and a heel end, said well arrangement comprising:
(i) a substantially vertical injection well extending into the upper portion of said reservoir suitable for the injection of oxygen-rich gas into said reservoir;
(ii) a substantially horizontal oil production well, positioned in said reservoir in a position below the lower end of said vertical injection well and substantially aligned with it; and (iii) a plurality of substantially vertical vent wells for removal of flue gases, said substantially vertical vent wells extending into the upper portion of said reservoir and substantially aligned along the line of said substantially horizontal production well.
In a second aspect of the present invention there is provided a method for recovering hydrocarbons from a subterranean reservoir comprising providing a subterranean reservoir with at least one well arrangement according to the first aspect of the present invention and carrying out the following steps:
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
(ii) combusting said oxygen rich gas in said hydrocarbon reservoir thereby heating, upgrading and reducing the viscosity of said hydrocarbon mixture;
(iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
Detailed Description of the Invention The present invention relates to particular well arrangements for the recovery of hydrocarbons. As used herein the phrase "well arrangement" is used to refer to an ordered grouping or organised structure of a number of wells within a reservoir. The term "well" refers to a hole drilled into the reservoir for use in the recovery of hydrocarbons. The term "well" is often used interchangeably with wellbore.
The well arrangements described herein facilitate the recovery of hydrocarbon, especially heavy hydrocarbons, from subterranean reservoirs. As used herein the phrase "subterranean reservoir" refers to a collection or accumulation that exists below the surface of the earth, e.g. under a sea or ocean bed. A hydrocarbon reservoir is therefore a mass of hydrocarbons that has accumulated in the porous rock existing below the earth's surface. The present invention is particularly applicable to the recovery of hydrocarbons from off-shore subterranean reservoirs, i.e. from reservoirs existing below a sea or ocean bed.
A typical subterranean reservoir comprises at least two distinct zones.
Nearest to the earth's surface is a covering of overburden which does not comprise any hydrocarbon.
Below the overburden lies at least one portion of the reservoir that contains hydrocarbons. This is referred to herein as the hydrocarbon-containing portion of the reservoir.
The hydrocarbon-containing portion of the reservoir comprises an upper portion and a lower portion. The upper portion generally refers to the uppermost 50% of the hydrocarbon-containing reservoir, more preferably the uppermost 40% and still more preferably the uppermost 30% of the reservoir. This portion is the portion of the hydrocarbon-containing reservoir that is nearest the surface of the reservoir.
Correspondingly the lower portion generally refers to the deepest portion of the reservoir, preferabaly the lowermost 50% of the hydrocarbon-containing reservoir, still more preferably the lowermost 40% of the reservoir and still more preferably the lowermost 30% of the reservoir.
The well arrangements described herein facilitate the recovery of hydrocarbon, especially heavy hydrocarbons, from subterranean reservoirs. As used herein the phrase "subterranean reservoir" refers to a collection or accumulation that exists below the surface of the earth, e.g. under a sea or ocean bed. A hydrocarbon reservoir is therefore a mass of hydrocarbons that has accumulated in the porous rock existing below the earth's surface. The present invention is particularly applicable to the recovery of hydrocarbons from off-shore subterranean reservoirs, i.e. from reservoirs existing below a sea or ocean bed.
A typical subterranean reservoir comprises at least two distinct zones.
Nearest to the earth's surface is a covering of overburden which does not comprise any hydrocarbon.
Below the overburden lies at least one portion of the reservoir that contains hydrocarbons. This is referred to herein as the hydrocarbon-containing portion of the reservoir.
The hydrocarbon-containing portion of the reservoir comprises an upper portion and a lower portion. The upper portion generally refers to the uppermost 50% of the hydrocarbon-containing reservoir, more preferably the uppermost 40% and still more preferably the uppermost 30% of the reservoir. This portion is the portion of the hydrocarbon-containing reservoir that is nearest the surface of the reservoir.
Correspondingly the lower portion generally refers to the deepest portion of the reservoir, preferabaly the lowermost 50% of the hydrocarbon-containing reservoir, still more preferably the lowermost 40% of the reservoir and still more preferably the lowermost 30% of the reservoir.
Configuring the substantially vertical vent wells so that they are substantially aligned along the line of the horizontal production well enables the number of wells that has to be drilled to be minimised, as they are aligned in the direction of the developing combustion front.
By "a substantially vertical vent well" we mean a wellbore that is vertical or near-vertical for the removal of flue gases (i.e. gases produced in the reservoir as a result of the combustion of the hydrocarbons in said reservoir). By substantially vertical is meant that the well is at an angle of 75-900 to the earth's surface, more preferably at an angle of 80-900 to the earth's surface, still more preferably at an angle of 85-90 to the earth's surface, most preferably perpendicular to the earth's surface, for at least 90 % of the total length of the vertical well, more preferably for at least 95 % of the total length of the vertical well. Furthermore, it is an important feature of the invention that the substantially vertical vent wells extend into the upper portion of the reservoir, i.e. the lower end of said vent well is completed in the upper portion of the reservoir. This maximises the collection of the flue gases as they are generated during the combustion process.
The well arrangement of the present invention comprises a plurality of vent wells that are substantially aligned along the line of the substantially horizontal production well.
This means that the vent wells are preferably aligned in a row. Preferably the vent wells are equally spaced apart along the row. Preferably the final vent well in a row is in the vicinity of the heel of the production well (see below). The number of vent wells present in a well arrangement will depend on a number of factors, e.g. the type of the reservoir, the amount of hydrocarbon present, the size of the injection and vent wells etc, but generally 3 to 10 vent wells will be present, more preferably 4 to 8 vent wells.
The well arrangement has a substantially vertical injection well extending into the upper portion of the reservoir suitable for the injection of oxygen-rich gas into the reservoir.
The oxygen-rich gas can, for example, be air, oxygen or recycled gas with oxygen added. A preferred oxygen-rich gas for use in the methods of the present invention comprises at least 20% by volume oxygen. Particularly preferred oxygen-rich gases comprise at least 30 % by volume, more preferably at least 40 % by volume oxygen.
Particularly preferred oxygen-rich gas comprises 20-100 % by volume oxygen, more preferably 30-90 % by volume oxygen, still more preferably 40-85 % by volume oxygen, e.g. about 50 to 80 % by volume oxygen.
By "a substantially vertical vent well" we mean a wellbore that is vertical or near-vertical for the removal of flue gases (i.e. gases produced in the reservoir as a result of the combustion of the hydrocarbons in said reservoir). By substantially vertical is meant that the well is at an angle of 75-900 to the earth's surface, more preferably at an angle of 80-900 to the earth's surface, still more preferably at an angle of 85-90 to the earth's surface, most preferably perpendicular to the earth's surface, for at least 90 % of the total length of the vertical well, more preferably for at least 95 % of the total length of the vertical well. Furthermore, it is an important feature of the invention that the substantially vertical vent wells extend into the upper portion of the reservoir, i.e. the lower end of said vent well is completed in the upper portion of the reservoir. This maximises the collection of the flue gases as they are generated during the combustion process.
The well arrangement of the present invention comprises a plurality of vent wells that are substantially aligned along the line of the substantially horizontal production well.
This means that the vent wells are preferably aligned in a row. Preferably the vent wells are equally spaced apart along the row. Preferably the final vent well in a row is in the vicinity of the heel of the production well (see below). The number of vent wells present in a well arrangement will depend on a number of factors, e.g. the type of the reservoir, the amount of hydrocarbon present, the size of the injection and vent wells etc, but generally 3 to 10 vent wells will be present, more preferably 4 to 8 vent wells.
The well arrangement has a substantially vertical injection well extending into the upper portion of the reservoir suitable for the injection of oxygen-rich gas into the reservoir.
The oxygen-rich gas can, for example, be air, oxygen or recycled gas with oxygen added. A preferred oxygen-rich gas for use in the methods of the present invention comprises at least 20% by volume oxygen. Particularly preferred oxygen-rich gases comprise at least 30 % by volume, more preferably at least 40 % by volume oxygen.
Particularly preferred oxygen-rich gas comprises 20-100 % by volume oxygen, more preferably 30-90 % by volume oxygen, still more preferably 40-85 % by volume oxygen, e.g. about 50 to 80 % by volume oxygen.
By "a substantially vertical injection well" we mean a wellbore that is vertical or near-vertical for the injection of oxygen-rich gas into the reservoir. By substantially vertical is meant that the well is at an angle of 75-900 to the earth's surface, more preferably at an angle of 80-900 to the earth's surface, still more preferably at an angle of 85-90 to the earth's surface, most preferably perpendicular to the earth's surface, for at least 90 %
of the total length of the vertical well, more preferably for at least 95 % of the total length of the vertical well. Again, it is an important feature of the invention that the substantially vertical injection well extends into the upper portion of the reservoir, i.e.
the lower end of said injection well is completed in the upper portion of the reservoir.
The well arrangement of the present invention has a substantially horizontal oil production well, positioned in the reservoir in a position below the lower end of the vertical injection well and substantially aligned with it. By "a substantially horizontal oil production well" we mean a horizontal or near-horizontal wellbore that is configured to capture the mobilised hydrocarbons and water produced as a result of the combustion process of the present invention. By substantially horizontal is meant that the well is within 15 of being parallel to the earth's surface, more preferably within 10 of being parallel to the earth's surface, still more preferably within 5 of being parallel to the earth's surface, e.g. parallel to the earth's surface, for at least 90 % of the total length of the substantially horizontal well, more preferably for at least 95 % of the total length of the substantially horizontal well.
Each producer well also preferably comprises a further section, typically a substantially vertical section, which extends from the horizontal well to the surface. This further, e.g.
vertical, section is preferably integral with the horizontal well. This enables gases and fluids to be injected and/or pumped into and out of the wells to the reservoir surface.
The same definition of "vertical" applies here as given above.
The horizontal producer well, together with its vertical section, define a shape that is sometimes likened to a foot. The part of the well where the vertical section meets or joins the horizontal well is generally referred to as the heel and the end of the horizontal well as the toe. Sometimes the terminology "heel" and "toe" is also applied in relation to the reservoir. In this case, the heel part of the reservoir refers to the part of the reservoir in which the heel of the production well is present and the toe part of the reservoir refers to the part in which the toe of the production well is present.
The horizontal oil production well is located in a position that is below the lower end of the plurality of vent wells and substantially aligned with them. By this we mean that it is disposed below the end of the vent wells and aligned or near-aligned with the line of the plurality of vent wells. Preferably the distance between the bottom of the injection well and the production well is about 2-20 metres, more preferably about 5-10 metres.
Preferably the production well is located in the lower portion of the reservoir. By lower portion is meant the lower 50% of the total height of the oil-bearing reservoir, e.g. the lower 10-50% of the total height of the oil-bearing reservoir.
Preferably the production well is fitted with a slotted liner conventional in the art to permit ingress of hydrocarbon mixture from the reservoir. In a particularly preferred embodiment, the substantially horizontal production well should be configured to segregate gas and liquid flows such that the hydrocarbons and water are carried by it and transported to the heel section from where they are transferred (see below), whereas the gas is vented via the casing. In some embodiments, if gas lifting of the produced hydrocarbon is desired, the horizontal well can be suitably configured to permit a small amount of gas to enter through the tubing and be retained.
The well arrangements and methods of the invention are based on an in situ combustion process wherein a gas is injected into the oil-bearing formation where it combusts with hydrocarbon present therein. A combustion front forms and the area of formation adjacent to the combustion front is heated and upgraded, resulting in the viscosity of any hydrocarbon present in this zone being reduced. As the hydrocarbon softens and becomes flowable, gravity forces it downwards towards the substantially horizontal production well from where it can be produced. The well arrangement of the present invention reduces the pressure difference between the substantially vertical injection well and the substantially horizontal production well, as a result of which there is considerably improved control of propagation and sweep of the combustion front to maximise the effects of both combustion and gravity drives. This is partly achieved because the injection well is always located in a relatively close location to the combustion front. Furthermore, the well arrangement efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases.
If the reservoir is dipping, the toe end of the substantially horizontal production well is preferably on the updip side.
Preferably, in the well arrangement of the present invention the substantially vertical injection well is initially located at the toe end of the subterranean reservoir.
In a particularly preferred embodiment of the well arrangement of the present invention the substantially vertical vent wells are configured such that they can be switched to act as a substantially vertical injection well. This can be achieved because the injection well and vent wells are preferably aligned. Preferably the injection well and the vent wells are also of similar, e.g. identical, length. This arrangement is particularly efficient because as the combustion front spreads from the toe end of the reservoir, away from the initial substantially vertical injection well, when it reaches the first of the substantially vertical vent wells it is then possible to switch the operation of said vent well so that it operates as an injection well. At the same time, the next substantially vertical vent well along the line of the substantially horizontal production well is opened so that it is able to act as a vent to the flue gases generated by the combustion front.
This dual-configuration of the wells allows this swapping of functions from vent wells to injection wells all along the length of the substantially horizontal production well as the combustion front continues to develop and reach each in turn. Hence, it provides a clear advantage over prior art arrangements owing to the efficiency of operation that is possible as a result of the minimisation of the number of wells that has to be drilled and the maximisation of both the effects of both combustion and gravity drives that results.
The mobilised hydrocarbons produced using the well arrangement of the present invention can be recovered from the substantially horizontal production well by any means known in the art, e.g. by pumping it from the production well to the surface.
Typically, in the well arrangement according to the present invention hydrocarbons are recovered from the horizontal production well through tubing located near the heel end of said reservoir, usually by pumping through said tubing.
As used herein, the term "hydrocarbons" is used to refer to a combination of different hydrocarbons, i.e. to a combination of various types of molecules that contain carbon atoms and, in many cases, attached hydrogen atoms. "Hydrocarbons" may comprise a large number of different molecules having a wide range of molecular weights.
Generally at least 90 % by weight of the "hydrocarbons" in the reservoir consists of carbon and hydrogen atoms. Up to 10% by weight may be present as sulphur, nitrogen and oxygen as well as metals such as iron, nickel and vanadium (i.e.
as measured sulphur, nitrogen, oxygen or metals). These are generally present in the form of impurities of the desired hydrocarbon mixture.
The well arrangement of the present invention is particularly useful in the recovery of heavy hydrocarbon mixtures. A heavy hydrocarbon mixture comprises a greater proportion of hydrocarbons having a higher molecular weight than a relatively lighter hydrocarbon mixture. As used herein a heavy hydrocarbon mixture preferably has an API gravity of less than about 15 , preferably less than 12 , still more preferably less than 10 , e.g. less than 8 . It is particularly preferred if the API gravity of the heavy hydrocarbon mixture to be recovered is from about 5 to about 15 , more preferably from about 6 to about 12 , still more preferably about 7 to about 12 , e.g.
about 7.5-9 . Examples of heavy hydrocarbon mixtures that typically have API gravities falling in these ranges are bitumens, tars, oil shales and oil sand deposits.
A plurality of the well arrangements of the present invention may be located in a single reservoir as an array of substantially horizontal production wells, substantially vertical injection wells and substantially vertical vent wells. Such arrays enable the pressure difference between the substantially vertical injection wells and the substantially horizontal production wells to be reduced, optimising the effects of both combustion and gravity drives. While maintaining an overall gas balance, the air and vent gas rates of the individual injection wells and vent wells may be varied periodically in such arrays to encourage cross flows between the well units. The aim of this is to improve the areal sweep of the combustion front.
As noted above, the second aspect of the present invention is a method for recovering hydrocarbons from a subterranean reservoir comprising providing a reservoir with at least one well arrangement according to the first aspect of the present invention and carrying out the following steps:
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
of the total length of the vertical well, more preferably for at least 95 % of the total length of the vertical well. Again, it is an important feature of the invention that the substantially vertical injection well extends into the upper portion of the reservoir, i.e.
the lower end of said injection well is completed in the upper portion of the reservoir.
The well arrangement of the present invention has a substantially horizontal oil production well, positioned in the reservoir in a position below the lower end of the vertical injection well and substantially aligned with it. By "a substantially horizontal oil production well" we mean a horizontal or near-horizontal wellbore that is configured to capture the mobilised hydrocarbons and water produced as a result of the combustion process of the present invention. By substantially horizontal is meant that the well is within 15 of being parallel to the earth's surface, more preferably within 10 of being parallel to the earth's surface, still more preferably within 5 of being parallel to the earth's surface, e.g. parallel to the earth's surface, for at least 90 % of the total length of the substantially horizontal well, more preferably for at least 95 % of the total length of the substantially horizontal well.
Each producer well also preferably comprises a further section, typically a substantially vertical section, which extends from the horizontal well to the surface. This further, e.g.
vertical, section is preferably integral with the horizontal well. This enables gases and fluids to be injected and/or pumped into and out of the wells to the reservoir surface.
The same definition of "vertical" applies here as given above.
The horizontal producer well, together with its vertical section, define a shape that is sometimes likened to a foot. The part of the well where the vertical section meets or joins the horizontal well is generally referred to as the heel and the end of the horizontal well as the toe. Sometimes the terminology "heel" and "toe" is also applied in relation to the reservoir. In this case, the heel part of the reservoir refers to the part of the reservoir in which the heel of the production well is present and the toe part of the reservoir refers to the part in which the toe of the production well is present.
The horizontal oil production well is located in a position that is below the lower end of the plurality of vent wells and substantially aligned with them. By this we mean that it is disposed below the end of the vent wells and aligned or near-aligned with the line of the plurality of vent wells. Preferably the distance between the bottom of the injection well and the production well is about 2-20 metres, more preferably about 5-10 metres.
Preferably the production well is located in the lower portion of the reservoir. By lower portion is meant the lower 50% of the total height of the oil-bearing reservoir, e.g. the lower 10-50% of the total height of the oil-bearing reservoir.
Preferably the production well is fitted with a slotted liner conventional in the art to permit ingress of hydrocarbon mixture from the reservoir. In a particularly preferred embodiment, the substantially horizontal production well should be configured to segregate gas and liquid flows such that the hydrocarbons and water are carried by it and transported to the heel section from where they are transferred (see below), whereas the gas is vented via the casing. In some embodiments, if gas lifting of the produced hydrocarbon is desired, the horizontal well can be suitably configured to permit a small amount of gas to enter through the tubing and be retained.
The well arrangements and methods of the invention are based on an in situ combustion process wherein a gas is injected into the oil-bearing formation where it combusts with hydrocarbon present therein. A combustion front forms and the area of formation adjacent to the combustion front is heated and upgraded, resulting in the viscosity of any hydrocarbon present in this zone being reduced. As the hydrocarbon softens and becomes flowable, gravity forces it downwards towards the substantially horizontal production well from where it can be produced. The well arrangement of the present invention reduces the pressure difference between the substantially vertical injection well and the substantially horizontal production well, as a result of which there is considerably improved control of propagation and sweep of the combustion front to maximise the effects of both combustion and gravity drives. This is partly achieved because the injection well is always located in a relatively close location to the combustion front. Furthermore, the well arrangement efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases.
If the reservoir is dipping, the toe end of the substantially horizontal production well is preferably on the updip side.
Preferably, in the well arrangement of the present invention the substantially vertical injection well is initially located at the toe end of the subterranean reservoir.
In a particularly preferred embodiment of the well arrangement of the present invention the substantially vertical vent wells are configured such that they can be switched to act as a substantially vertical injection well. This can be achieved because the injection well and vent wells are preferably aligned. Preferably the injection well and the vent wells are also of similar, e.g. identical, length. This arrangement is particularly efficient because as the combustion front spreads from the toe end of the reservoir, away from the initial substantially vertical injection well, when it reaches the first of the substantially vertical vent wells it is then possible to switch the operation of said vent well so that it operates as an injection well. At the same time, the next substantially vertical vent well along the line of the substantially horizontal production well is opened so that it is able to act as a vent to the flue gases generated by the combustion front.
This dual-configuration of the wells allows this swapping of functions from vent wells to injection wells all along the length of the substantially horizontal production well as the combustion front continues to develop and reach each in turn. Hence, it provides a clear advantage over prior art arrangements owing to the efficiency of operation that is possible as a result of the minimisation of the number of wells that has to be drilled and the maximisation of both the effects of both combustion and gravity drives that results.
The mobilised hydrocarbons produced using the well arrangement of the present invention can be recovered from the substantially horizontal production well by any means known in the art, e.g. by pumping it from the production well to the surface.
Typically, in the well arrangement according to the present invention hydrocarbons are recovered from the horizontal production well through tubing located near the heel end of said reservoir, usually by pumping through said tubing.
As used herein, the term "hydrocarbons" is used to refer to a combination of different hydrocarbons, i.e. to a combination of various types of molecules that contain carbon atoms and, in many cases, attached hydrogen atoms. "Hydrocarbons" may comprise a large number of different molecules having a wide range of molecular weights.
Generally at least 90 % by weight of the "hydrocarbons" in the reservoir consists of carbon and hydrogen atoms. Up to 10% by weight may be present as sulphur, nitrogen and oxygen as well as metals such as iron, nickel and vanadium (i.e.
as measured sulphur, nitrogen, oxygen or metals). These are generally present in the form of impurities of the desired hydrocarbon mixture.
The well arrangement of the present invention is particularly useful in the recovery of heavy hydrocarbon mixtures. A heavy hydrocarbon mixture comprises a greater proportion of hydrocarbons having a higher molecular weight than a relatively lighter hydrocarbon mixture. As used herein a heavy hydrocarbon mixture preferably has an API gravity of less than about 15 , preferably less than 12 , still more preferably less than 10 , e.g. less than 8 . It is particularly preferred if the API gravity of the heavy hydrocarbon mixture to be recovered is from about 5 to about 15 , more preferably from about 6 to about 12 , still more preferably about 7 to about 12 , e.g.
about 7.5-9 . Examples of heavy hydrocarbon mixtures that typically have API gravities falling in these ranges are bitumens, tars, oil shales and oil sand deposits.
A plurality of the well arrangements of the present invention may be located in a single reservoir as an array of substantially horizontal production wells, substantially vertical injection wells and substantially vertical vent wells. Such arrays enable the pressure difference between the substantially vertical injection wells and the substantially horizontal production wells to be reduced, optimising the effects of both combustion and gravity drives. While maintaining an overall gas balance, the air and vent gas rates of the individual injection wells and vent wells may be varied periodically in such arrays to encourage cross flows between the well units. The aim of this is to improve the areal sweep of the combustion front.
As noted above, the second aspect of the present invention is a method for recovering hydrocarbons from a subterranean reservoir comprising providing a reservoir with at least one well arrangement according to the first aspect of the present invention and carrying out the following steps:
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
(ii) combusting said oxygen rich gas in said hydrocarbon reservoir thereby heating, upgrading and reducing the viscosity of said hydrocarbon mixture;
(iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
As noted above, the well arrangement of the present invention has the potential to reduce the pressure difference between the substantially vertical injection well and the substantially horizontal production wells, as a result of which it is possible to achieve considerably improved control of propagation and sweep of the combustion front compared to the SAGD and COSH techniques of the prior art. The well arrangement makes it possible to maximise the effects of both combustion and gravity drives.
Furthermore, it efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases. Adoption of the method of the second aspect of the present invention enables these to be achieved to the fullest possible effect.
The oxygen-rich gas is typically injected into the formation using conventional equipment for the handling of gases. Preferably the oxygen-rich gas is injected into the formation at a pressure less than the fracturing pressure of the formation.
Preferably the oxygen-rich gas is injected into the formation at a pressure that is greater than the reservoir pressure. Generally the oxygen-rich gas is injected at a pressure that is -0-20 bar, preferably 5-20 bar, e.g. about 10 bar, greater than the reservoir pressure. When the oxygen-rich gas comprises a mixture, e.g. of oxygen and CO2, the gases may be mixed prior to injection or co-injected. Preferably the gases are mixed prior to injection.
Prior to the injection of the oxygen-rich gas, the formation is preferably heated. This ensures that ignition and combustion will occur when the oxygen-rich gas is injected.
Preferably the formation is heated prior to injection by steam, in particular, by cyclic steam stimulation. Steam may be injected into the formation using conventional techniques. The preheating stage is preferably continued until the reservoir reaches a high enough temperature to maintain combustion. Preferably the preheating step achieves a reservoir temperature of 150-300 C, still more preferably 200-250 C. The generation of steam is, however, an energy consuming and CO2 producing process, therefore the amount of steam used is preferably minimised. The CO2 produced during steam generation may optionally be captured and stored in a formation and/or incorporated into the oxygen-rich gas injected into the formation.
(iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
As noted above, the well arrangement of the present invention has the potential to reduce the pressure difference between the substantially vertical injection well and the substantially horizontal production wells, as a result of which it is possible to achieve considerably improved control of propagation and sweep of the combustion front compared to the SAGD and COSH techniques of the prior art. The well arrangement makes it possible to maximise the effects of both combustion and gravity drives.
Furthermore, it efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases. Adoption of the method of the second aspect of the present invention enables these to be achieved to the fullest possible effect.
The oxygen-rich gas is typically injected into the formation using conventional equipment for the handling of gases. Preferably the oxygen-rich gas is injected into the formation at a pressure less than the fracturing pressure of the formation.
Preferably the oxygen-rich gas is injected into the formation at a pressure that is greater than the reservoir pressure. Generally the oxygen-rich gas is injected at a pressure that is -0-20 bar, preferably 5-20 bar, e.g. about 10 bar, greater than the reservoir pressure. When the oxygen-rich gas comprises a mixture, e.g. of oxygen and CO2, the gases may be mixed prior to injection or co-injected. Preferably the gases are mixed prior to injection.
Prior to the injection of the oxygen-rich gas, the formation is preferably heated. This ensures that ignition and combustion will occur when the oxygen-rich gas is injected.
Preferably the formation is heated prior to injection by steam, in particular, by cyclic steam stimulation. Steam may be injected into the formation using conventional techniques. The preheating stage is preferably continued until the reservoir reaches a high enough temperature to maintain combustion. Preferably the preheating step achieves a reservoir temperature of 150-300 C, still more preferably 200-250 C. The generation of steam is, however, an energy consuming and CO2 producing process, therefore the amount of steam used is preferably minimised. The CO2 produced during steam generation may optionally be captured and stored in a formation and/or incorporated into the oxygen-rich gas injected into the formation.
The methods of the present invention may also employ an ignition device. Any commercially available device may be used, e.g. a downhole burner. When present, the ignition device is preferably placed in the injection well. Preferred ignition devices achieve temperatures of at least 300 C, e.g. 300-500 C.
The oxygen-rich gas used for combustion can, for example, be air, oxygen or recycled gas with oxygen added, as previously discussed. Air is preferred.
In a preferred embodiment of the method of the present invention, the oxygen rich gas is air injected at a rate of from 25,000 to 100,000 m3/day. By maintaining an injection rate within this range, this intake of oxygen (air comprising approximately 20% oxygen gas) is sufficient to ensure in situ heat generation in the reservoir.
The flue gases are vented to regulate the reservoir pressure after injection of the oxygen rich gas at a pre-determined operating pressure (e.g. about 10 bar greater than the reservoir pressure). Preferably, the flue gases are vented at from 80-95%, e.g. 85-90% the rate of injection of the oxygen rich gas to regulate the reservoir pressure.
In a particularly preferred embodiment of the method of the present invention, the flue gases vented via said substantially vertical vent wells are captured and then re-injected into said subterranean reservoir via the previous substantially vertical injection well.
This has two desirable effects. First, it maximises oxygen usage in the burnt chamber.
Second, it reduces emission of green house gases into the Earth's atmosphere which makes this embodiment particularly environmentally favourable.
The mobilised hydrocarbons recovered from the production well preferably have an API
of 9-20 , more preferably 10-17 , still more preferably 11-15 . Thus, in preferred methods of the invention, the hydrocarbons in the reservoir undergo upgrading during recovery that increases the API of the mobilised hydrocarbons by up to 5 , e.g. by 1 to 50.
Having an ability to control the temperature achieved in the reservoir by combustion is advantageous because it impacts upon the nature of the hydrocarbon mixture produced from the recovery process. Generally the higher the temperature achieved by the combustion in the reservoir the greater the amount of upgrading of hydrocarbon mixture occurs. As used herein, the term "upgrading" generally refers to the process of altering a hydrocarbon mixture to have more desirable properties, e.g. to reduce the average molecular weight of the hydrocarbons present in the mixture and correspondingly its viscosity. Upgrading during the recovery process is therefore generally desirable. In in situ combustion processes, upgrading is believed to occur by thermal cracking. At the same time, however, the temperature of the reservoir needs to be controlled so that the combustion area, as well as the combustion gases, is contained in the part of the formation where they are desired. In the method of the present invention, the injection rate of the oxygen rich gas and the concentration of oxygen in said gas are carefully controlled to ensure that combustion is maintained at the desired temperature and in the correct areas of the reservoir.
The liquid (i.e. mobilised hydrocarbons and water) production rate is controlled based on the temperature at the bottom of the reservoir in the vicinity of the substantially horizontal production well. Typically, this will be in the region of 300 C.
This is to avoid heat damage and coking in the substantially horizontal production well.
Preferably, a low casing gas pressure should be used in the substantially horizontal production well to draw the combustion surface down in the reservoir. However, it is very important that the combustion zone should not come into contact with the substantially horizontal production well, but instead should be maintained above it.
It is possible in the method of the present invention to inject a small amount of water with the oxygen rich gas via the substantially vertical injection well. The aim of this is to optimise the energy utility. The heat from the combustion will heat the injected water such that it produces superheated steam. The superheated steam will propagate to the combustion front, and into the formation heating the bitumen and mobilising it so that it can be recovered. This provides an additional heat-based effect akin to the SAGD recovery effect (it is different to ISC where upgrading occurs due to the combustion leaving behind a "coke" component).
The water can also provide temperature control, as water is a good regulator due to its high latent heat of vaporization. In a particularly preferred embodiment of the present invention, as the advancing hydrocarbon front reaches each substantially vertical vent well in turn moving from the toe end towards the heel end, it is switched to act as a substantially vertical injection well and the next vent well along the line of said substantially horizontal production well between said substantially vertical injection well and said heel end is opened to act as the new vent well. In a particularly preferred embodiment of this aspect of the present invention, the previous substantially vertical injection well is either shut-in or is converted to a substantially vertical flue gas injector or is used for water disposal when the subsequent vent well is converted to become the new substantially vertical injection well.
This dual-configuration of the wells allows this swapping of functions from vent wells to injection wells all along the length of the substantially horizontal production well as the combustion front continues to develop and reach each in turn. Hence, it provides a clear advantage over alternative prior art arrangements owing to the efficiency of operation that is possible as a result of the minimisation of the number of wells that have to be drilled and the maximisation of both the effects of both combustion and gravity drives that results.
The present invention may be further understood by consideration of the following examples, which include reference to the following drawings.
Brief Description of Drawings Figure 1 is a top schematic view of a subterranean reservoir comprising three well arrangements according to the present invention;
Figures 2 and 3 are isometric schematic views of the subterranean reservoir comprising one of said well arrangements after combustion has been initiated (depicted at different times); and Figure 4 is a top schematic view of a subterranean reservoir where a pattern has been depleted and the line drive operation is being continued by the addition of new pattern on the heel side of the depleted pattern.
Examples Referring to Figure 1, this shows a top schematic view of a subterranean reservoir comprising three well arrangements according to the present invention in the initial configuration before combustion has begun.
A covering of overburden (not shown in Figure 1) lies above the oil-bearing formation 1.
Vertical injection wells 2 are drilled downward through the overburden. The injection wells 2 are completed in the upper portion of said oil-bearing formation 1.
Vent wells 3 are also drilled through the overburden and are completed in the upper portion of the oil-bearing formation.
The oxygen-rich gas used for combustion can, for example, be air, oxygen or recycled gas with oxygen added, as previously discussed. Air is preferred.
In a preferred embodiment of the method of the present invention, the oxygen rich gas is air injected at a rate of from 25,000 to 100,000 m3/day. By maintaining an injection rate within this range, this intake of oxygen (air comprising approximately 20% oxygen gas) is sufficient to ensure in situ heat generation in the reservoir.
The flue gases are vented to regulate the reservoir pressure after injection of the oxygen rich gas at a pre-determined operating pressure (e.g. about 10 bar greater than the reservoir pressure). Preferably, the flue gases are vented at from 80-95%, e.g. 85-90% the rate of injection of the oxygen rich gas to regulate the reservoir pressure.
In a particularly preferred embodiment of the method of the present invention, the flue gases vented via said substantially vertical vent wells are captured and then re-injected into said subterranean reservoir via the previous substantially vertical injection well.
This has two desirable effects. First, it maximises oxygen usage in the burnt chamber.
Second, it reduces emission of green house gases into the Earth's atmosphere which makes this embodiment particularly environmentally favourable.
The mobilised hydrocarbons recovered from the production well preferably have an API
of 9-20 , more preferably 10-17 , still more preferably 11-15 . Thus, in preferred methods of the invention, the hydrocarbons in the reservoir undergo upgrading during recovery that increases the API of the mobilised hydrocarbons by up to 5 , e.g. by 1 to 50.
Having an ability to control the temperature achieved in the reservoir by combustion is advantageous because it impacts upon the nature of the hydrocarbon mixture produced from the recovery process. Generally the higher the temperature achieved by the combustion in the reservoir the greater the amount of upgrading of hydrocarbon mixture occurs. As used herein, the term "upgrading" generally refers to the process of altering a hydrocarbon mixture to have more desirable properties, e.g. to reduce the average molecular weight of the hydrocarbons present in the mixture and correspondingly its viscosity. Upgrading during the recovery process is therefore generally desirable. In in situ combustion processes, upgrading is believed to occur by thermal cracking. At the same time, however, the temperature of the reservoir needs to be controlled so that the combustion area, as well as the combustion gases, is contained in the part of the formation where they are desired. In the method of the present invention, the injection rate of the oxygen rich gas and the concentration of oxygen in said gas are carefully controlled to ensure that combustion is maintained at the desired temperature and in the correct areas of the reservoir.
The liquid (i.e. mobilised hydrocarbons and water) production rate is controlled based on the temperature at the bottom of the reservoir in the vicinity of the substantially horizontal production well. Typically, this will be in the region of 300 C.
This is to avoid heat damage and coking in the substantially horizontal production well.
Preferably, a low casing gas pressure should be used in the substantially horizontal production well to draw the combustion surface down in the reservoir. However, it is very important that the combustion zone should not come into contact with the substantially horizontal production well, but instead should be maintained above it.
It is possible in the method of the present invention to inject a small amount of water with the oxygen rich gas via the substantially vertical injection well. The aim of this is to optimise the energy utility. The heat from the combustion will heat the injected water such that it produces superheated steam. The superheated steam will propagate to the combustion front, and into the formation heating the bitumen and mobilising it so that it can be recovered. This provides an additional heat-based effect akin to the SAGD recovery effect (it is different to ISC where upgrading occurs due to the combustion leaving behind a "coke" component).
The water can also provide temperature control, as water is a good regulator due to its high latent heat of vaporization. In a particularly preferred embodiment of the present invention, as the advancing hydrocarbon front reaches each substantially vertical vent well in turn moving from the toe end towards the heel end, it is switched to act as a substantially vertical injection well and the next vent well along the line of said substantially horizontal production well between said substantially vertical injection well and said heel end is opened to act as the new vent well. In a particularly preferred embodiment of this aspect of the present invention, the previous substantially vertical injection well is either shut-in or is converted to a substantially vertical flue gas injector or is used for water disposal when the subsequent vent well is converted to become the new substantially vertical injection well.
This dual-configuration of the wells allows this swapping of functions from vent wells to injection wells all along the length of the substantially horizontal production well as the combustion front continues to develop and reach each in turn. Hence, it provides a clear advantage over alternative prior art arrangements owing to the efficiency of operation that is possible as a result of the minimisation of the number of wells that have to be drilled and the maximisation of both the effects of both combustion and gravity drives that results.
The present invention may be further understood by consideration of the following examples, which include reference to the following drawings.
Brief Description of Drawings Figure 1 is a top schematic view of a subterranean reservoir comprising three well arrangements according to the present invention;
Figures 2 and 3 are isometric schematic views of the subterranean reservoir comprising one of said well arrangements after combustion has been initiated (depicted at different times); and Figure 4 is a top schematic view of a subterranean reservoir where a pattern has been depleted and the line drive operation is being continued by the addition of new pattern on the heel side of the depleted pattern.
Examples Referring to Figure 1, this shows a top schematic view of a subterranean reservoir comprising three well arrangements according to the present invention in the initial configuration before combustion has begun.
A covering of overburden (not shown in Figure 1) lies above the oil-bearing formation 1.
Vertical injection wells 2 are drilled downward through the overburden. The injection wells 2 are completed in the upper portion of said oil-bearing formation 1.
Vent wells 3 are also drilled through the overburden and are completed in the upper portion of the oil-bearing formation.
The production well 6 is substantially horizontal and is aligned with, and positioned below, the row of vent wells 3. The production well 6 is located in a lower region of the oil-bearing formation 1. The production well 6 is preferably provided with a liner (not shown) as is conventional in the art.
Preferably, the air injection wells 2 are located at the toe ends 4 of the horizontal wells 6, while the vent wells 3 are configured such that they are approximately equally spaced along the horizontal wells 6 and the final vent wells 3 are at the heel ends 5 of said horizontal wells 6.
In most cases it will be desirable to preheat the formation 1 prior to commencing in situ combustion. This prepares the cold heavy hydrocarbon for ignition and develops enhanced hydrocarbon mobility in the reservoir. Preheating may be achieved by injecting steam through the injection wells 2 and optionally through the vent wells 3 and/or the production wells 6. It is generally desirable to inject steam through all types of wells so fluid communication between the injection wells 2, vent wells 3 and production wells 6 is achieved. Oil may be recovered in production wells 6 during this preheating step. When the reservoir is sufficiently heated, combustion may be started.
Referring to Figures 2 and 3, they show isometric schematic views of the subterranean reservoir comprising one of said well arrangements after combustion has been initiated (Figures 2 and 3 depicting different stages after combustion has been initiated).
Features that are also shown in Figure 1 are designated by the same reference numeral. The overburden through which the wells are drilled can be seen in Figures 2 and 3 (see 7).
Oxygen-rich gas is injected into injection well 2 located at the toe end of the reservoir to initiate combustion. Thereafter a combustion chamber forms around the injection well 2. The combustion chambers naturally spread and eventually form a continuous chamber that links all of the injection wells 2 in the entire reservoir. The front of the combustion zone 8 heats heavy hydrocarbon in its vicinity thereby increasing the hydrocarbon mobility and enabling it to flow. Under the forces of gravity, the mobilised heavy hydrocarbon flows downwards towards production well 6, from there the partially upgraded heavy hydrocarbon is lifted to the surface facilities via well 6.
At the start of combustion, the combustion front 8 is located very close to the injection well 2 and therefore the heavy hydrocarbon that is heated and recovered is from this portion of the reservoir. As the combustion front spreads, however, heavy hydrocarbon that is located further away from the injection wells becomes sufficiently heated to begin to flow. Thus Figure 2 shows an isometric schematic of a well arrangement shortly after combustion has been initiated and Figure 3 shows an isometric schematic of the same well arrangement some time later.
As the combustion front 8 approaches the first vent well 3 (see Figure 2), it is switched to act as an injection well 2 (see Figure 3) and the next vent well 3 along the line of said horizontal production well 6 between said injection well 2 and said heel end 5 is opened to act as the new vent well 3. After the vent well 3 has been converted to an injection well 2, the first injection well 2 is either shut-in or it is converted to a flue gas injector or used for water disposal.
The preferred properties of the heavy hydrocarbon mixture in the formation and the heavy hydrocarbon mixture recovered after in situ combustion are shown in the Table below.
Parameter Bitumen Bitumen from in situ combustion Viscosity at 20C (CP) >555.000 1000-100,000 =
S content (wt%) 3.2-5 2.0-4.0 = .
API gravity ( ) <7.9 10 -16 If there are more than two sections along the horizontal well arrangement of the present invention, the procedure shown for Section #2 will be repeated for the subsequent sections in the well, with each vent well 3 being converted to an injection well 2 as the combustion front 8 reaches it and the next vent well 3 being opened.
A multi-section well arrangement of this type is shown in Figure 4.
Furthermore, Figure 4 depicts a top schematic view of a subterranean reservoir where an oil bearing formation 1 has been depleted and the line drive operation is being continued by the addition of new patterns on the heel side of the depleted oil bearing formation 1.
Hence, where the oil bearing formation 1 of the first well formation has become depleted at the heel 5 of the depleted oil bearing formation 1, new horizontal wells 6' are laid in continuation at the beginning (toe end 4') of the new oil bearing formation 1'.
As before, injection wells 2' are completed in the upper portion of said oil-bearing formation 1'. Vent wells 3' are also drilled through the overburden and are completed in the upper portion of the oil-bearing formation 1'. In this context, it is important that the horizontal and vertical wells of an old section are abandoned in accordance with proper abandonment procedures to prevent combustion gases from being leaked to surface through these wells.
The production well 6' is substantially horizontal and is aligned with, and positioned below, the row of vent wells 3'. The heating, combustion and switching from vent to injection well procedure is conducted as previously and the mobilised heavy hydrocarbon is lifted from production well 6' to the surface.
The well arrangement and method of the present invention has a number of clear advantages over the prior art well arrangements and methods:
(i) the well arrangement of the present invention reduces the pressure difference between the injection well and the horizontal wells, as a result of which there is considerably improved control of propagation and sweep of the combustion front, thus maximising the effects of both combustion and gravity drives.
(ii) the well arrangement of the present invention minimises the number of wells that have to be drilled;
(iii) the well arrangement of the present invention efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases;
(iv) the preferred embodiment of the well arrangement of the present invention that allows the swapping of functions from vent wells to injection wells all along the length of the horizontal production well as the combustion front continues to develop and reaches each in turn provides a clear advantage over alternative prior art arrangements owing to the efficiency of operation that is possible; this is due to the minimisation of the number of wells that has to be drilled and the maximisation of both the effects of both combustion and gravity drives that results; and (v) the preferred embodiment of the method of the present invention in which the flue gases that are vented via the vertical vent wells are captured and then re-injected into said subterranean reservoir via the vertical injection well has two clear advantages over the prior art; namely, it maximises oxygen usage in the burnt chamber and it reduces emission of green house gases into the Earth's atmosphere which clearly makes this embodiment particularly environmentally favourable.
Preferably, the air injection wells 2 are located at the toe ends 4 of the horizontal wells 6, while the vent wells 3 are configured such that they are approximately equally spaced along the horizontal wells 6 and the final vent wells 3 are at the heel ends 5 of said horizontal wells 6.
In most cases it will be desirable to preheat the formation 1 prior to commencing in situ combustion. This prepares the cold heavy hydrocarbon for ignition and develops enhanced hydrocarbon mobility in the reservoir. Preheating may be achieved by injecting steam through the injection wells 2 and optionally through the vent wells 3 and/or the production wells 6. It is generally desirable to inject steam through all types of wells so fluid communication between the injection wells 2, vent wells 3 and production wells 6 is achieved. Oil may be recovered in production wells 6 during this preheating step. When the reservoir is sufficiently heated, combustion may be started.
Referring to Figures 2 and 3, they show isometric schematic views of the subterranean reservoir comprising one of said well arrangements after combustion has been initiated (Figures 2 and 3 depicting different stages after combustion has been initiated).
Features that are also shown in Figure 1 are designated by the same reference numeral. The overburden through which the wells are drilled can be seen in Figures 2 and 3 (see 7).
Oxygen-rich gas is injected into injection well 2 located at the toe end of the reservoir to initiate combustion. Thereafter a combustion chamber forms around the injection well 2. The combustion chambers naturally spread and eventually form a continuous chamber that links all of the injection wells 2 in the entire reservoir. The front of the combustion zone 8 heats heavy hydrocarbon in its vicinity thereby increasing the hydrocarbon mobility and enabling it to flow. Under the forces of gravity, the mobilised heavy hydrocarbon flows downwards towards production well 6, from there the partially upgraded heavy hydrocarbon is lifted to the surface facilities via well 6.
At the start of combustion, the combustion front 8 is located very close to the injection well 2 and therefore the heavy hydrocarbon that is heated and recovered is from this portion of the reservoir. As the combustion front spreads, however, heavy hydrocarbon that is located further away from the injection wells becomes sufficiently heated to begin to flow. Thus Figure 2 shows an isometric schematic of a well arrangement shortly after combustion has been initiated and Figure 3 shows an isometric schematic of the same well arrangement some time later.
As the combustion front 8 approaches the first vent well 3 (see Figure 2), it is switched to act as an injection well 2 (see Figure 3) and the next vent well 3 along the line of said horizontal production well 6 between said injection well 2 and said heel end 5 is opened to act as the new vent well 3. After the vent well 3 has been converted to an injection well 2, the first injection well 2 is either shut-in or it is converted to a flue gas injector or used for water disposal.
The preferred properties of the heavy hydrocarbon mixture in the formation and the heavy hydrocarbon mixture recovered after in situ combustion are shown in the Table below.
Parameter Bitumen Bitumen from in situ combustion Viscosity at 20C (CP) >555.000 1000-100,000 =
S content (wt%) 3.2-5 2.0-4.0 = .
API gravity ( ) <7.9 10 -16 If there are more than two sections along the horizontal well arrangement of the present invention, the procedure shown for Section #2 will be repeated for the subsequent sections in the well, with each vent well 3 being converted to an injection well 2 as the combustion front 8 reaches it and the next vent well 3 being opened.
A multi-section well arrangement of this type is shown in Figure 4.
Furthermore, Figure 4 depicts a top schematic view of a subterranean reservoir where an oil bearing formation 1 has been depleted and the line drive operation is being continued by the addition of new patterns on the heel side of the depleted oil bearing formation 1.
Hence, where the oil bearing formation 1 of the first well formation has become depleted at the heel 5 of the depleted oil bearing formation 1, new horizontal wells 6' are laid in continuation at the beginning (toe end 4') of the new oil bearing formation 1'.
As before, injection wells 2' are completed in the upper portion of said oil-bearing formation 1'. Vent wells 3' are also drilled through the overburden and are completed in the upper portion of the oil-bearing formation 1'. In this context, it is important that the horizontal and vertical wells of an old section are abandoned in accordance with proper abandonment procedures to prevent combustion gases from being leaked to surface through these wells.
The production well 6' is substantially horizontal and is aligned with, and positioned below, the row of vent wells 3'. The heating, combustion and switching from vent to injection well procedure is conducted as previously and the mobilised heavy hydrocarbon is lifted from production well 6' to the surface.
The well arrangement and method of the present invention has a number of clear advantages over the prior art well arrangements and methods:
(i) the well arrangement of the present invention reduces the pressure difference between the injection well and the horizontal wells, as a result of which there is considerably improved control of propagation and sweep of the combustion front, thus maximising the effects of both combustion and gravity drives.
(ii) the well arrangement of the present invention minimises the number of wells that have to be drilled;
(iii) the well arrangement of the present invention efficiently produces the mobilised liquids (i.e. softened, flowable hydrocarbons and water) and combustion flue gases;
(iv) the preferred embodiment of the well arrangement of the present invention that allows the swapping of functions from vent wells to injection wells all along the length of the horizontal production well as the combustion front continues to develop and reaches each in turn provides a clear advantage over alternative prior art arrangements owing to the efficiency of operation that is possible; this is due to the minimisation of the number of wells that has to be drilled and the maximisation of both the effects of both combustion and gravity drives that results; and (v) the preferred embodiment of the method of the present invention in which the flue gases that are vented via the vertical vent wells are captured and then re-injected into said subterranean reservoir via the vertical injection well has two clear advantages over the prior art; namely, it maximises oxygen usage in the burnt chamber and it reduces emission of green house gases into the Earth's atmosphere which clearly makes this embodiment particularly environmentally favourable.
Claims (16)
1. A well arrangement suitable for the recovery by an in situ combustion process of hydrocarbons from a subterranean reservoir having a toe end and a heel end, said well arrangement comprising:
(i) a substantially vertical injection well extending into the upper portion of said reservoir suitable for the injection of oxygen-rich gas into said reservoir;
(ii) a substantially horizontal oil production well, positioned in said reservoir in a position below the lower end of said vertical injection well and substantially aligned with it; and (iii) a plurality of substantially vertical vent wells for removal of flue gases, said substantially vertical vent wells extending into the upper portion of said reservoir and substantially aligned along the line of said substantially horizontal production well.
(i) a substantially vertical injection well extending into the upper portion of said reservoir suitable for the injection of oxygen-rich gas into said reservoir;
(ii) a substantially horizontal oil production well, positioned in said reservoir in a position below the lower end of said vertical injection well and substantially aligned with it; and (iii) a plurality of substantially vertical vent wells for removal of flue gases, said substantially vertical vent wells extending into the upper portion of said reservoir and substantially aligned along the line of said substantially horizontal production well.
2. A well arrangement according to claim 1, wherein said substantially vertical injection well is initially located at the toe end of said reservoir.
3. A well arrangement according to claim 1 or claim 2, wherein said substantially vertical vent wells are configured such that they can be switched to act as a substantially vertical injection well.
4. A well arrangement according to any one of claims 1 to 3, wherein hydrocarbons are recovered from the substantially horizontal production well through tubing located near the heel end of said reservoir.
5. A subterranean reservoir comprising a plurality of well arrangements according to any one of claims 1 to 4, wherein said well arrangements are arranged as a parallel array.
6. A method for recovering hydrocarbons from a subterranean reservoir comprising providing a subterranean reservoir with at least one well arrangement as defined in any one of claims 1 to 4 and carrying out the following steps:
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
(ii) combusting said oxygen rich gas in said hydrocarbon reservoir thereby heating, upgrading and reducing the viscosity of said hydrocarbon mixture; and (iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
(i) injecting an oxygen rich gas via said substantially vertical injection well into said hydrocarbon reservoir and opening the substantially vertical vent well that is closest to said substantially vertical injection well along the line of the substantially horizontal production well towards the heel end;
(ii) combusting said oxygen rich gas in said hydrocarbon reservoir thereby heating, upgrading and reducing the viscosity of said hydrocarbon mixture; and (iii) recovering mobilised hydrocarbon from said substantially horizontal production well.
7. A method according to claim 6, wherein as the advancing hydrocarbon front reaches each substantially vertical vent well in turn moving from the toe end towards the heel end, it is switched to act as a substantially vertical injection well and the next vent well along the line of said substantially horizontal production well between said substantially vertical injection well and said heel end is opened to act as the new vent well.
8. A method according to claim 7, wherein the previous substantially vertical injection well is either shut-in or is converted to a substantially vertical flue gas injector or is used for water disposal when the subsequent vent well is converted to become the new substantially vertical injection well.
9. A method according to any one of claims 6 to 8, wherein said oxygen-rich gas comprises 20-100% by volume oxygen.
10. A method according to any one of claims 6 to 8, wherein said oxygen-rich gas comprises 30-90% by volume oxygen.
11. A method according to any one of claims 6 to 8, wherein said oxygen-rich gas comprises 50 to 80% by volume oxygen.
12. A method according to any one of claims 6 to 11, wherein the oxygen rich gas is air injected at a rate of from 25,000 to 100,000 m3/day.
13. A method according to any one of claims 6 to 12, wherein the flue gases are vented at from 80-95% the rate of injection of the oxygen rich gas.
14. A method according to any one of claims 6 to 13, wherein the flue gases vented via said substantially vertical vent wells are captured and then re-injected into said subterranean reservoir via the previous vertical injection well.
15. A method according to any one of claims 6 to 14, wherein said recovered mobilised hydrocarbons have an API of 11-15°.
16. A method according to any one of claims 6 to 15, wherein said subterranean reservoir is provided with a plurality of well arrangements according to claims 1 to 4 of the present invention.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GB1100549.3 | 2011-01-13 | ||
| GBGB1100549.3A GB201100549D0 (en) | 2011-01-13 | 2011-01-13 | Process for the recovery of heavy oil and bitumen in situ combustion |
| PCT/EP2012/050403 WO2012095473A2 (en) | 2011-01-13 | 2012-01-12 | Process for the recovery of heavy oil and bitumen using in-situ combustion |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2824168A1 true CA2824168A1 (en) | 2012-07-19 |
Family
ID=43736377
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2824168A Abandoned CA2824168A1 (en) | 2011-01-13 | 2012-01-12 | Process for the recovery of heavy oil and bitumen using in-situ combustion |
Country Status (4)
| Country | Link |
|---|---|
| CA (1) | CA2824168A1 (en) |
| GB (1) | GB201100549D0 (en) |
| RU (1) | RU2013137758A (en) |
| WO (1) | WO2012095473A2 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN107939373A (en) * | 2018-01-17 | 2018-04-20 | 西南石油大学 | A kind of new combustion in situ heavy oil development well pattern structure and method |
Families Citing this family (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2014075166A1 (en) * | 2012-11-14 | 2014-05-22 | Nexen Energy Ulc | Use of steam-assisted gravity drainage with oxygen ("sagdox") in the recovery of bitumen in lean zones ("lz-sagdox") |
| RU2570865C1 (en) * | 2014-08-21 | 2015-12-10 | Евгений Николаевич Александров | System for improvement of airlift efficiency at pumping formation fluid from subsurface resources |
| CN104594863B (en) * | 2014-11-24 | 2017-09-01 | 中国石油天然气股份有限公司 | Method for enhancing in-situ combustion exploitation of oil reservoir |
| CN104594865B (en) * | 2014-11-25 | 2017-05-10 | 中国石油天然气股份有限公司 | Method for exploiting heavy oil reservoir by controllable reverse in-situ combustion |
| CN106050207B (en) * | 2016-07-29 | 2019-05-07 | 中国石油天然气股份有限公司 | Equipment for injecting coal powder into oil reservoir and ignition method for in-situ combustion |
Family Cites Families (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5211230A (en) * | 1992-02-21 | 1993-05-18 | Mobil Oil Corporation | Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion |
| CA2096034C (en) | 1993-05-07 | 1996-07-02 | Kenneth Edwin Kisman | Horizontal well gravity drainage combustion process for oil recovery |
| US8167036B2 (en) | 2006-01-03 | 2012-05-01 | Precision Combustion, Inc. | Method for in-situ combustion of in-place oils |
| US7793720B2 (en) * | 2008-12-04 | 2010-09-14 | Conocophillips Company | Producer well lugging for in situ combustion processes |
| CA2678347C (en) * | 2009-09-11 | 2010-09-21 | Excelsior Energy Limited | System and method for enhanced oil recovery from combustion overhead gravity drainage processes |
-
2011
- 2011-01-13 GB GBGB1100549.3A patent/GB201100549D0/en not_active Ceased
-
2012
- 2012-01-12 WO PCT/EP2012/050403 patent/WO2012095473A2/en active Application Filing
- 2012-01-12 CA CA2824168A patent/CA2824168A1/en not_active Abandoned
- 2012-01-12 RU RU2013137758/03A patent/RU2013137758A/en not_active Application Discontinuation
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN107939373A (en) * | 2018-01-17 | 2018-04-20 | 西南石油大学 | A kind of new combustion in situ heavy oil development well pattern structure and method |
| CN107939373B (en) * | 2018-01-17 | 2019-03-15 | 西南石油大学 | A kind of novel combustion in situ heavy oil development well pattern structure and method |
Also Published As
| Publication number | Publication date |
|---|---|
| WO2012095473A2 (en) | 2012-07-19 |
| WO2012095473A3 (en) | 2013-06-27 |
| GB201100549D0 (en) | 2011-03-02 |
| RU2013137758A (en) | 2015-02-20 |
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