CA2744640A1 - Cyclic combustion recovery process for mature in situ operations - Google Patents
Cyclic combustion recovery process for mature in situ operations Download PDFInfo
- Publication number
- CA2744640A1 CA2744640A1 CA2744640A CA2744640A CA2744640A1 CA 2744640 A1 CA2744640 A1 CA 2744640A1 CA 2744640 A CA2744640 A CA 2744640A CA 2744640 A CA2744640 A CA 2744640A CA 2744640 A1 CA2744640 A1 CA 2744640A1
- Authority
- CA
- Canada
- Prior art keywords
- well
- oxidizing gas
- pairs
- combustion
- infill
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/2406—Steam assisted gravity drainage [SAGD]
- E21B43/2408—SAGD in combination with other methods
Abstract
An in situ process for recovering heavy hydrocarbons from an underground reservoir includes providing an array of well pairs, e.g. SAGD, for recovery of heavy hydrocarbons; operating the array to produce hydrocarbons and forming mobilized chambers; establishing fluid communication between the mobilized chambers to create an interwell mobilized zone; operating at least one well as an oxidizing gas injection well; injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir; promoting displacement of the combustion through the interwell communication zone to sweep the array of well pairs; regulating the array to pressurize the interwell communication zone; regulating the array of well pairs to effectuate blowdown and produce a blowdown portion of the heavy hydrocarbons therefrom; and cyclically repeating the oxidizing gas injection to blowdown steps.
Description
CYCLIC COMBUSTION RECOVERY PROCESS FOR MATURE IN
SITU OPERATIONS
FIELD OF THE INVENTION
The present invention relates to a process for recovering bitumen/oil from an underground reservoir and more precisely to a cyclic combustion recovery process for mature in situ thermal operations.
BACKGROUND OF THE INVENTION
In situ steam based thermal extraction is one of the most extensively used techniques for recovering heavy hydrocarbons, such as heavy oils and bitumen, from underground reservoirs. For example, this technique has been successful in extracting bitumen from the Northern Alberta oil sands. Cyclic Steam Simulation (CSS) and Steam Assisted Gravity Drainage (SAGD) are two major processes that have been used for in situ thermal extraction. However, each of these processes has an economic limit and when this limit is reached;
steam injection is terminated or scaled back. The economic limit of a SAGD
operation depends of course on several factors. One indicator that a SAGD
process is approaching its economic limit is often when the steam chambers which have developed in the reservoir have stopped increasing in volume. In the latter stage of a SADG operation as it approaches or reaches its economic limit, the SAGD operation is generally referred to as being "mature". In the case of multiple SAGD well pairs adjacent to one another, which is often the case in the field, individual steam chambers developed above and around each well pair begin to coalesce with one another until one common steam chamber is formed. Eventually an equilibrium is reached at which point the steam chamber generally stops growing, assuming a constant steam injection rate is maintained. The maturity of a SAGD operation can also be indicated for example in terms of the steam-oil ratio (SOR). When the SOR is too high, the process becomes uneconomic. However, when a SAGD operation has reached maturity, significant oil/bitumen still remains in the reservoir and the SAGD
SITU OPERATIONS
FIELD OF THE INVENTION
The present invention relates to a process for recovering bitumen/oil from an underground reservoir and more precisely to a cyclic combustion recovery process for mature in situ thermal operations.
BACKGROUND OF THE INVENTION
In situ steam based thermal extraction is one of the most extensively used techniques for recovering heavy hydrocarbons, such as heavy oils and bitumen, from underground reservoirs. For example, this technique has been successful in extracting bitumen from the Northern Alberta oil sands. Cyclic Steam Simulation (CSS) and Steam Assisted Gravity Drainage (SAGD) are two major processes that have been used for in situ thermal extraction. However, each of these processes has an economic limit and when this limit is reached;
steam injection is terminated or scaled back. The economic limit of a SAGD
operation depends of course on several factors. One indicator that a SAGD
process is approaching its economic limit is often when the steam chambers which have developed in the reservoir have stopped increasing in volume. In the latter stage of a SADG operation as it approaches or reaches its economic limit, the SAGD operation is generally referred to as being "mature". In the case of multiple SAGD well pairs adjacent to one another, which is often the case in the field, individual steam chambers developed above and around each well pair begin to coalesce with one another until one common steam chamber is formed. Eventually an equilibrium is reached at which point the steam chamber generally stops growing, assuming a constant steam injection rate is maintained. The maturity of a SAGD operation can also be indicated for example in terms of the steam-oil ratio (SOR). When the SOR is too high, the process becomes uneconomic. However, when a SAGD operation has reached maturity, significant oil/bitumen still remains in the reservoir and the SAGD
chambers and it would be desirable to recover as much as possible of the remaining hydrocarbons.
In situ combustion is another technique which can be used to extract oil/bitumen from underground reservoirs. In general, in situ combustion involves the injection of an oxidizing gas such as air into the reservoir to enable combustion of some of the reservoir hydrocarbons underground as fuel, thus heating and forcing the mobilized hydrocarbons to facilitate production. There are several known methods of in situ combustion using various injection and production wells patterns and orientations, oxidizing gas injection strategies and well constructions and designs. However, in various reservoir geologies and scenarios, in situ combustion has not been a proven method for bitumen recovery. Indeed, several in situ combustion field projects have been prematurely terminated, due to low fluid mobility in the reservoir and oxygen or combustion front rapid breakthrough from the producers among other challenges. Oxygen breakthrough has several challenges including hazards such as light hydrocarbon vapor/gas explosions at producers resulting in tubular damage, flue gas breakthrough at producers causing wellbore gas-liquid interference during production, and acid gas resulting in corrosion both in downhole equipment and surface facilities.
Canadian patent No. 2,594,414 discloses a technology for recovering oil/bitumen using an air injection method into wells previously employed for a SAGD operation. Continuous air injection is conducted through an injection well while producers are maintained open in production mode throughout the process. This purportedly allows keeping the SAGD zones at constant pressure. The speed of combustion front in the formation is purportedly designed by the rate of air to be injected. However, continuous air injection is a technique which is difficult to apply to bitumen recovery, for instance because of the problem of air or oxygen early breakthrough observed in in situ combustion field applications. One reason for difficulties is due to significant heterogeneity in the reservoir, especially after SAGD operation, where hot spots and cold spots are observed. Hot spots show a high mobility of gas/air due to lower oil/bitumen saturation and lower oil/bitumen viscosity, compared to cold spots. Fluid saturation and temperature distributions may vary from place to place at the mature stage of a SAGD operation, which creates heterogeneity to fluid mobility. Therefore, air or oxygen tend to flow through the area that is of the lowest flowing resistance, i.e. the highest directional permeability streaks or most depleted portions within the SAGD chamber. Another reason for difficulties is that within mature steam chamber, the air injector(s) will connect to producer(s) through some high permeability streaks that are of the lowest flow resistance to air or flue gas and become early oxygen/combustion breakthrough paths, if measures related to restriction of production are not taken.
There is thus a need for a technology that overcomes at least some of the drawbacks of what is known in the field, such as the above-mentioned drawback that may result from premature oxygen/combustion breakthrough and/or low mobility of fluids, that increases the recovery of hydrocarbons from an underground reservoir at a mature stage of a SAGD operation and/or that enables hydrocarbon recovery while reducing or maintaining a low steam-oil ratio.
SUMMARY OF THE INVENTION
The present invention responds to the above need by providing a cyclic combustion recovery process for mature in situ thermal operations.
More particularly, the invention provides an in situ process for recovering heavy hydrocarbons from an underground reservoir, comprising:
(a) providing an array of well pairs for gravity controlled recovery of heavy hydrocarbons, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well;
In situ combustion is another technique which can be used to extract oil/bitumen from underground reservoirs. In general, in situ combustion involves the injection of an oxidizing gas such as air into the reservoir to enable combustion of some of the reservoir hydrocarbons underground as fuel, thus heating and forcing the mobilized hydrocarbons to facilitate production. There are several known methods of in situ combustion using various injection and production wells patterns and orientations, oxidizing gas injection strategies and well constructions and designs. However, in various reservoir geologies and scenarios, in situ combustion has not been a proven method for bitumen recovery. Indeed, several in situ combustion field projects have been prematurely terminated, due to low fluid mobility in the reservoir and oxygen or combustion front rapid breakthrough from the producers among other challenges. Oxygen breakthrough has several challenges including hazards such as light hydrocarbon vapor/gas explosions at producers resulting in tubular damage, flue gas breakthrough at producers causing wellbore gas-liquid interference during production, and acid gas resulting in corrosion both in downhole equipment and surface facilities.
Canadian patent No. 2,594,414 discloses a technology for recovering oil/bitumen using an air injection method into wells previously employed for a SAGD operation. Continuous air injection is conducted through an injection well while producers are maintained open in production mode throughout the process. This purportedly allows keeping the SAGD zones at constant pressure. The speed of combustion front in the formation is purportedly designed by the rate of air to be injected. However, continuous air injection is a technique which is difficult to apply to bitumen recovery, for instance because of the problem of air or oxygen early breakthrough observed in in situ combustion field applications. One reason for difficulties is due to significant heterogeneity in the reservoir, especially after SAGD operation, where hot spots and cold spots are observed. Hot spots show a high mobility of gas/air due to lower oil/bitumen saturation and lower oil/bitumen viscosity, compared to cold spots. Fluid saturation and temperature distributions may vary from place to place at the mature stage of a SAGD operation, which creates heterogeneity to fluid mobility. Therefore, air or oxygen tend to flow through the area that is of the lowest flowing resistance, i.e. the highest directional permeability streaks or most depleted portions within the SAGD chamber. Another reason for difficulties is that within mature steam chamber, the air injector(s) will connect to producer(s) through some high permeability streaks that are of the lowest flow resistance to air or flue gas and become early oxygen/combustion breakthrough paths, if measures related to restriction of production are not taken.
There is thus a need for a technology that overcomes at least some of the drawbacks of what is known in the field, such as the above-mentioned drawback that may result from premature oxygen/combustion breakthrough and/or low mobility of fluids, that increases the recovery of hydrocarbons from an underground reservoir at a mature stage of a SAGD operation and/or that enables hydrocarbon recovery while reducing or maintaining a low steam-oil ratio.
SUMMARY OF THE INVENTION
The present invention responds to the above need by providing a cyclic combustion recovery process for mature in situ thermal operations.
More particularly, the invention provides an in situ process for recovering heavy hydrocarbons from an underground reservoir, comprising:
(a) providing an array of well pairs for gravity controlled recovery of heavy hydrocarbons, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well;
(b) operating the array of adjacent well pairs to produce hydrocarbons from the production wells and forming mobilized chambers within the reservoir extending from corresponding well pairs;
(c) establishing fluid communication between the mobilized chambers of adjacent ones of the well pairs to create an interwell mobilized zone;
(d) operating at least one well as an oxidizing gas injection well;
(e) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(f) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(g) regulating the array of well pairs to pressurize the interwell communication zone;
(h) regulating the array of well pairs to effectuate blowdown and produce a blowdown portion of the heavy hydrocarbons therefrom;
and (i) cyclically repeating steps d) to h).
In one aspect, step d) comprises converting a fluid injection well into the oxidizing gas injection well.
In another optional aspect, the process includes operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
In another optional aspect, the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
In another optional aspect, step f) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively 5 reaches each of the well pairs.
In another optional aspect, both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
In another optional aspect, both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
In another optional aspect, the restricting of each of the well pairs is performed upon breakthrough of combustion gas there-through.
In another optional aspect, step g) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
In another optional aspect, step h) comprises operating at least one of the wells of the array of well pairs in production mode.
In another optional aspect, step h) comprises operating the production wells in production mode.
In another optional aspect, step h) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
In another optional aspect, the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
(c) establishing fluid communication between the mobilized chambers of adjacent ones of the well pairs to create an interwell mobilized zone;
(d) operating at least one well as an oxidizing gas injection well;
(e) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(f) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(g) regulating the array of well pairs to pressurize the interwell communication zone;
(h) regulating the array of well pairs to effectuate blowdown and produce a blowdown portion of the heavy hydrocarbons therefrom;
and (i) cyclically repeating steps d) to h).
In one aspect, step d) comprises converting a fluid injection well into the oxidizing gas injection well.
In another optional aspect, the process includes operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
In another optional aspect, the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
In another optional aspect, step f) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively 5 reaches each of the well pairs.
In another optional aspect, both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
In another optional aspect, both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
In another optional aspect, the restricting of each of the well pairs is performed upon breakthrough of combustion gas there-through.
In another optional aspect, step g) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
In another optional aspect, step h) comprises operating at least one of the wells of the array of well pairs in production mode.
In another optional aspect, step h) comprises operating the production wells in production mode.
In another optional aspect, step h) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
In another optional aspect, the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
In another optional aspect, the underground reservoir is further provided with at least one infill well positioned in between two adjacent well pairs.
In another optional aspect, step c) comprises establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
In another optional aspect, step d) comprises converting the infill well into the oxidizing gas injection well.
In another optional aspect, step f) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, step g) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
In another optional aspect, step h) comprises operating each of the at least one infill well in production mode.
In another optional aspect, step i) comprises selecting the same well as the oxidizing gas injection well for each cycle.
In another optional aspect, step i) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
In another optional aspect, a single well is used as the oxidizing gas injection well.
In another optional aspect, step c) comprises establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
In another optional aspect, step d) comprises converting the infill well into the oxidizing gas injection well.
In another optional aspect, step f) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, step g) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
In another optional aspect, step h) comprises operating each of the at least one infill well in production mode.
In another optional aspect, step i) comprises selecting the same well as the oxidizing gas injection well for each cycle.
In another optional aspect, step i) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
In another optional aspect, a single well is used as the oxidizing gas injection well.
In another optional aspect, the oxidizing gas injection well is on one end of the interwell communication zone.
In another optional aspect, the oxidizing gas injection well is the injection well of an outside one of the well pairs.
In another optional aspect, the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
In another optional aspect, the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
The invention also provides a cyclic in situ combustion method for a mature steam assisted gravity drainage (SAGD) operation in an underground reservoir, the mature SAGD operation comprising an array of well pairs generally parallel to each other and an interwell communication zone between the well pairs, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well, the cyclic in situ combustion method comprising:
(i) operating at least one well as an oxidizing gas injection well;
(ii) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(iii) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(iv) pressurizing the interwell communication zone;
(v) producing a blowdown portion of the heavy hydrocarbons therefrom; and (vi) cyclically repeating steps (i) to (v).
In one aspect, step (i) comprises converting a fluid injection well of one of the well pairs into the oxidizing gas injection well.
In another optional aspect, the process includes operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
In another optional aspect, the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
In another optional aspect, step (iii) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
In another optional aspect, both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
In another optional aspect, both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of combustion gas there-through.
In another optional aspect, step (iv) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
In another optional aspect, the oxidizing gas injection well is the injection well of an outside one of the well pairs.
In another optional aspect, the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
In another optional aspect, the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
The invention also provides a cyclic in situ combustion method for a mature steam assisted gravity drainage (SAGD) operation in an underground reservoir, the mature SAGD operation comprising an array of well pairs generally parallel to each other and an interwell communication zone between the well pairs, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well, the cyclic in situ combustion method comprising:
(i) operating at least one well as an oxidizing gas injection well;
(ii) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(iii) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(iv) pressurizing the interwell communication zone;
(v) producing a blowdown portion of the heavy hydrocarbons therefrom; and (vi) cyclically repeating steps (i) to (v).
In one aspect, step (i) comprises converting a fluid injection well of one of the well pairs into the oxidizing gas injection well.
In another optional aspect, the process includes operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
In another optional aspect, the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
In another optional aspect, step (iii) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
In another optional aspect, both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
In another optional aspect, both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
In another optional aspect, the restricting of each of the well pairs is preformed upon breakthrough of combustion gas there-through.
In another optional aspect, step (iv) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
In another optional aspect, step (v) comprises operating at least one of the wells of the array of well pairs in production mode.
In another optional aspect, step (v) comprises operating the production wells in production mode.
In another optional aspect, step (v) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
In another optional aspect, the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
In another optional aspect, the process includes providing at least one infill well positioned in between two adjacent well pairs.
In another optional aspect, the process includes establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
In another optional aspect, the process includes converting the infill well into the oxidizing gas injection well.
In another optional aspect, step (iii) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, step (iv) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
In another optional aspect, step (v) comprises operating each of the at least 5 one infill well in production mode.
In another optional aspect, step (vi) comprises selecting the same well as the oxidizing gas injection well for each cycle.
In another optional aspect, step (vi) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
In another optional aspect, step (v) comprises operating the production wells in production mode.
In another optional aspect, step (v) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
In another optional aspect, the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
In another optional aspect, the process includes providing at least one infill well positioned in between two adjacent well pairs.
In another optional aspect, the process includes establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
In another optional aspect, the process includes converting the infill well into the oxidizing gas injection well.
In another optional aspect, step (iii) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
In another optional aspect, step (iv) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
In another optional aspect, step (v) comprises operating each of the at least 5 one infill well in production mode.
In another optional aspect, step (vi) comprises selecting the same well as the oxidizing gas injection well for each cycle.
In another optional aspect, step (vi) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
10 In another optional aspect, a single well is used as the oxidizing gas injection well.
In another optional aspect, the oxidizing gas injection well is on one end of the interwell communication zone.
In another optional aspect, the oxidizing gas injection well is the injection well of an outside one of the well pairs.
In another optional aspect, the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
The process of claim 55, wherein the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
In another optional aspect, step (v) is performed so as to establish fluid communication between the interwell communication zone and the at least one infill well.
In another optional aspect, the interwell communication zone has a bitumen saturation of from about 0.20 to less than about 0.05.
In another optional aspect, the oxidizing gas injection well injects air at an injection flux of about 0.3 to about 1.2 m3(ST)/m2.hour.
In another optional aspect, the oxidizing gas injection well is on one end of the interwell communication zone.
In another optional aspect, the oxidizing gas injection well is the injection well of an outside one of the well pairs.
In another optional aspect, the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
The process of claim 55, wherein the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
In another optional aspect, step (v) is performed so as to establish fluid communication between the interwell communication zone and the at least one infill well.
In another optional aspect, the interwell communication zone has a bitumen saturation of from about 0.20 to less than about 0.05.
In another optional aspect, the oxidizing gas injection well injects air at an injection flux of about 0.3 to about 1.2 m3(ST)/m2.hour.
In another optional aspect, the interwell communication zone has a porosity between about 0.30 to 0.35.
In another optional aspect, the interwell communication zone has a temperature of at least about 150 C upon initial injection of the oxidizing gas.
In another optional aspect, the interwell communication zone has a temperature of at least about 175 C upon initial injection of the oxidizing gas.
In another optional aspect, the interwell communication zone has a temperature of at least about 200 C upon initial injection of the oxidizing gas.
In another optional aspect, the oxidizing gas is oxygen, air, enriched air, a mixture steam/air or a mixture thereof.
In another optional aspect, the oxidizing gas further comprises additional components including methane or fuel gas or a combination thereof.
In another optional aspect, the oxidizing gas further comprises C02, recovered flue gases from a previous combustion cycle, and/or N2.
In another optional aspect, the oxidizing gas further comprises water.
In another optional aspect, the oxidizing gas is oxygen or air or a combination thereof.
In another optional aspect, the oxidizing gas is air.
It should also be understood that many of the above optional aspect of the present invention may be used in combination with one another.
BRIEF DESCRIPTION OF THE DRAWINGS
Figs 1 a to 1c are transverse front view schematics representing the formation stages of an interwell communication zone between mobilized chambers of adjacent SAGD well pairs within an underground reservoir according to steps a) to c) of a preferred embodiment of the process of the present invention.
Figs 2a to 2d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone according to steps d) to h) of an embodiment of the process of the present invention.
Fig 3a to 3d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone according to steps d) to h) of another embodiment of the process of the present invention.
Figs 4a, 4b and 4c are transverse front view schematics representing example configurations of arrays of four well pairs that may be used according to another embodiment of the process of the present invention.
Figs 5a to 5d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone of the coalesced steam chambers of SAGD well pairs and an infill well provided in between the SAGD well pairs in an underground reservoir according to steps d) to h) of another embodiment of the process of the present invention.
Figs 6a to 6d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone of the coalesced steam chambers of SAGD well pairs and an infill well in an underground reservoir according to steps d) to h) of another embodiment of the process of the present invention.
Figs 7a to 7d are transverse front view schematics representing the formation stages of an interwell communication zone between mobilized chambers of an array of SAGD well pairs and the addition of a plurality of infill wells and their fluid communication with the interwell communication zone in an underground reservoir according to another embodiment of the process of the present invention.
Figs 8a to 8d are top view schematics representing the formation stages of an interwell communication zone between mobilized chambers of an array of SAGD well pairs and an in situ combustion sweep within the interwell communication zone in an underground reservoir according to an embodiment of the process of the present invention.
Fig 9 is a schematic section view of a laboratory experimental combustion tube showing the locations of core centerline, wall thermocouples and wall heaters.
Fig 10 is a simplified schematic of an experimental combustion tube set-up.
Fig 11 represents the core temperature profiles observed in the combustion tube of Fig 9 during the laboratory experimental combustion.
While the invention will be described in conjunction with example embodiments, it will be understood that it is not intended to limit the scope of the invention to these embodiments. On the contrary, it is intended to cover all alternatives, modifications and equivalents as may be included as defined by the appended claims.
DETAILED DESCRIPTION
The present invention provides an in situ process for recovering heavy hydrocarbons from an underground reservoir. By heavy hydrocarbons, it is meant heavy crude oils or bitumen, i.e. petroleum or petroleum-like liquids or semisolids occurring naturally in porous and fractured media. Bitumen deposits are also called tar sand, oil sand, oil-impregnated rock, bituminous sand and the like. In the following detailed description, the terms heavy hydrocarbons, oil/bitumen and bitumen will be used interchangeably. It is noted that in a preferred embodiment of the present invention, the in situ combustion process is performed in a bitumen containing reservoir.
In the first step, the process of the invention provides an array of well pairs for gravity controlled recovery of heavy hydrocarbons. Each well pair comprises a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well. It should be understood that the horizontal portions of the injection and production wells may have varying inclinations along their trajectory depending on the reservoir characteristics and the in situ process used to recover the hydrocarbons from the reservoir. In a preferred embodiment, the well pairs have a configuration for performing a SAGD
operation. It should also be noted that the well pairs may be configured and operated to perform a number of other in situ recovery processes during their lifetime whereby other mobilizing fluids are injected into the reservoir such as hot water, solvents, steam and mixtures thereof.
At least two well pairs are used in the process of the invention. However, for the purpose of illustrating the invention, reference will be made to three well pairs as shown in Figs 1 to 3, four well pairs as shown in Fig 4, two well pairs and an infill well as shown in Figs 5 and 6, and 5 well pairs as shown in Figs and 8.
Referring to Fig la, there is shown an underground reservoir 10 provided with three well pairs 12. Each well pair 12 comprises a fluid injection well 20, 22, 24 having a horizontal portion and a production well 30, 32, 34 having a horizontal portion positioned below and aligned with the horizontal portion of the injection well. The horizontal portions of the injection and production wells are connected to vertical portions (not illustrated) which extend to the surface where they are used to inject fluids underground or recover the produced fluids for further processing.
In the second and third steps of the process of the invention, as illustrated in Fig lb as well as in Figs 7a and 8a, the array of adjacent well pairs 12 is operated to inject steam or another mobilizing fluid via the injection wells 20, 22, 24 and to produce hydrocarbons from the production wells 30, 32, 34, thereby forming mobilized chambers 14 within the reservoir extending from each well pair 12. Fluid communication is then established between the mobilized chambers 14 of adjacent well pairs 12 to create an interwell communication zone 16 which is shown in Fig 1c and also in Figs 2a to 2d, 3a to 3c, 5a to 5d, 6a to 6c, 7b to 7d and 8b to 8d. In one embodiment, the start-up phase includes injection or circulation of hot water, steam or solvent into the injection well such that fluid communication is established in between the injection well and production well. The processing is then ramped up as steam is injected into the bitumen baring formation through the fluid injection well 20, 22, 24 and production fluid comprising heated mobilized bitumen and condensate is recovered from the lower parallel-running horizontal production well 30, 32, 34 respectively. What has been called a mobilized steam chamber 5 14 is developed, upward and outward from each well pair. As steam flows toward the perimeter of the chamber 14, it encounters the lower temperature of the formation and condenses, causing heating and mobilization of the heavy hydrocarbons which drain downwardly with the condensate toward the production well. In this way heat is transferred to the bitumen, causing the 10 bitumen to warm up to the point of mobilization or flow ability, preferably under gravity control. Eventually, both the bitumen and steam condensate are recovered from the formation through the production well 30, 32, 34 located below the steam injection well 20, 22, 24. As the heated and mobilized bitumen drains down, fresh bitumen becomes exposed at an extraction interface that is 15 subsequently heated by the ongoing steam contact and its condensation. The continuous drainage of bitumen from the formation results in the steam filled bitumen depleted extraction chamber growing toward the top of the formation and then spreading sideways over time. This chamber is called a SAGD steam chamber, a gravity drainage chamber or a mobilized chamber. In time, continuously injecting steam into the chambers leads to expanding the mobilized chambers to the point of establishing fluid communication between the mobilized chambers of adjacent well pairs and creates an interwell communication zone 16. In other words, the chambers 14 coalesce to form a larger chamber where the well pairs 12 are in fluid communication with each other. Referring to Fig 7b, the interwell communication zone 16 preferably includes the individual mobilized chambers 14 of the entire array of SAGD well pairs 12. In typical SAGD operation, the interwell communication zone may usually have a porosity of between about 0.30 to about 0.35. More regarding the interwell communication zone 16 will be described herein-below in reference to Figs 8a-8d. When SAGD operation reaches the economic limit, usually when bitumen recovery factor is at least 50% of the original bitumen in place or SAGD recoverable reserve, steam injection is terminated. One can then say that the SAGD operation is mature. The temperature in the mature SAGD chambers is generally around about 190 C to about 257 C, which is based on the SAGD operating pressure from 1300kPa to 4500kPa. However, a temperature of at least above 150 C, and even more preferably above 200 C, is favourable for the next steps of the process of the invention including initiating in situ combustion in the mature SAGD chamber. Furthermore, residual hydrocarbons are still present in and around the mobilized chambers after SAGD operation, which will also favour combustion. In another optional aspect, the bitumen residual saturation in a mature SAGD chamber may be about 0.20 to less than about 0.05.
Referring to Figs 2a to 2d, there is shown the following steps of the process of the invention and more particularly those steps which allow recovering further oil/bitumen from the underground reservoir 10. As more particularly shown in Fig 2a, an oxidizing gas, e.g. oxygen or air, preferably air for availability and economic reasons is injected through a well, preferably through one of the fluid injecting wells 20 into the mature interwell chamber 16. Even though air is preferably injected in the process of the invention, it is also possible to inject other gases such as methane (e.g. pipelined methane), fuel gas (e.g. fuel gas from steam boiler), pure oxygen or enriched air (e.g. an oxygen concentration above 21%) as oxidizing gas and it is also possible to inject or co-inject additional gases at various steps of the process such as CO2 or N2, recovered flue gases from a previous combustion cycle, and the like. A mixture of water and air could also be used. Injection of a mixture steam/air is also possible.
In this latter case, the mole ratio of air to steam in this mixture is preferably more than 2%.
In another optional aspect, the air injection rate is based on the value of air required and of the minimum air flux to sustain in situ combustion. The minimum air flux is dependent upon the formation thickness, well length and well spacing. The injection rate is also dependent on the operating pressure and reservoir pressure. For example, for a typical SAGD well configuration and Athabasca bitumen formation, this rate may be estimated to be around 10,000 m3(ST)/day/well to 100,000 m3(ST)/day/well. In a preferred embodiment, the oxidizing gas injection flux may be about 3 to about 1.2 m3(ST)/m2.hour.
While it is preferred to convert one of the existing wells into the oxidizing gas injection well, it is also possible to provide an additional well, which may be vertical or horizontal, as the oxygen injection well. Due to the high temperature in the chamber and the presence of residual hydrocarbons, ignition occurs spontaneously and a combustion region forms around injecting well 20. It is worth noting that even though ignition is generally spontaneous, it would also be possible to initiate combustion through introduction of a source of ignition at the injection well. It is also possible to promote initial combustion by injecting a high oxygen content gas and then gradually scaling back oxygen content to the composition of air. At this step of initiating combustion, the producer well below the converted oxidizing gas injection well 20 is shut in while all the other wells (injectors and producers) 22, 32, 24 and 34 are preferably left open in production mode. The combustion region is then allowed to propagate through the interwell communication zone 16 encouraged in the direction of adjacent well pairs of the array as a result of pressure differential between the air injector 20 and the open wells 22, 32, 24 and 34. Injection of oxidizing gas is continued and when the first breakthrough of heat, combustion flue gases occurs at wells 22 and 32, or in response to another detected process parameter, these wells are restricted by choking or shutting in. For example, referring to Fig 2b, the well 22 is shut in upon arrival of the combustion front, while the downstream wells 24 and 34 are kept open to continue encouraging the combustion front to progress further along the interwell chamber 16. The timed restriction of the wells causes the advancing combustion front from prematurely breaking through and enables a continued advancement of the combustion across more of the interwell chamber. The combustion front is redirected toward the remaining open wells 24 and 34. In this way, the well pairs are operated such that each subsequent downstream well is choked or shut in upon arrival of the combustion front thus promoting the advancement of the combustion across and throughout the interwell region. Once the oxygen/combustion front is close to the last well pair, wells 24 and 34 in Fig 2c for example, the restriction procedure is applied to these wells. Fig 2c shows all wells being shut in except for the air injection well. Continuing air injection causes the reservoir pressure to rise till a desired pressure value. Then, air injection is terminated and that well may also be shut in. The pressure-up shut-in time may be provided to allow prolonged heating of the interwell chamber.
Even though Figs 2a to 2d only shows three well pairs, it should be understood that more well pairs could be present in the array and in the mature interwell chamber. The pressure-up phase could also be implemented sequentially until all the further wells are restricted.
Preferably, the pressure-up phase is reached by restricting production by either choking or shutting in wells 22, 32, 24 and 34, after oxygen or combustion front has arrived to these producer wells, while air is being injected. This results in pressure rising both in the mature SAGD chamber and its surrounding reservoir, especially in the upswept area. Thus, combustion front is forced to penetrate from the mature SAGD chamber into the adjacent portion of the reservoir which is upswept by steam and colder and which has a higher remaining oil/bitumen saturation. Therefore, more oxygen is consumed rather than flow breakthrough through the mature chamber that connected air injector 20 and wells 22, 32, 24 and 34. Thereby, more oil/bitumen is heated and eventually mobilized.
It is also worth mentioning that high energy can be released from the combustion or oxidation, and local combustion zone temperature can reach 300 C or more. Flue gases (mainly containing nitrogen and carbon dioxide) are generated as a result of these high temperature oxidation or combustion reactions, which displace and mobilize residual oil/bitumen to form oil/bitumen banks between the well pairs. Also, flue gas occupies the void volume which is left by the steam condensate, so as to allow gravity drainage to continuously take place within the mature chamber, and incremental oil/bitumen is recovered.
In another optional aspect, the interwell communication zone has a temperature of at least about 150 C upon initial injection of the oxidizing gas.
In another optional aspect, the interwell communication zone has a temperature of at least about 175 C upon initial injection of the oxidizing gas.
In another optional aspect, the interwell communication zone has a temperature of at least about 200 C upon initial injection of the oxidizing gas.
In another optional aspect, the oxidizing gas is oxygen, air, enriched air, a mixture steam/air or a mixture thereof.
In another optional aspect, the oxidizing gas further comprises additional components including methane or fuel gas or a combination thereof.
In another optional aspect, the oxidizing gas further comprises C02, recovered flue gases from a previous combustion cycle, and/or N2.
In another optional aspect, the oxidizing gas further comprises water.
In another optional aspect, the oxidizing gas is oxygen or air or a combination thereof.
In another optional aspect, the oxidizing gas is air.
It should also be understood that many of the above optional aspect of the present invention may be used in combination with one another.
BRIEF DESCRIPTION OF THE DRAWINGS
Figs 1 a to 1c are transverse front view schematics representing the formation stages of an interwell communication zone between mobilized chambers of adjacent SAGD well pairs within an underground reservoir according to steps a) to c) of a preferred embodiment of the process of the present invention.
Figs 2a to 2d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone according to steps d) to h) of an embodiment of the process of the present invention.
Fig 3a to 3d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone according to steps d) to h) of another embodiment of the process of the present invention.
Figs 4a, 4b and 4c are transverse front view schematics representing example configurations of arrays of four well pairs that may be used according to another embodiment of the process of the present invention.
Figs 5a to 5d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone of the coalesced steam chambers of SAGD well pairs and an infill well provided in between the SAGD well pairs in an underground reservoir according to steps d) to h) of another embodiment of the process of the present invention.
Figs 6a to 6d are transverse front view schematics representing the in situ combustion sweep, pressure-up and blowdown phases in the interwell communication zone of the coalesced steam chambers of SAGD well pairs and an infill well in an underground reservoir according to steps d) to h) of another embodiment of the process of the present invention.
Figs 7a to 7d are transverse front view schematics representing the formation stages of an interwell communication zone between mobilized chambers of an array of SAGD well pairs and the addition of a plurality of infill wells and their fluid communication with the interwell communication zone in an underground reservoir according to another embodiment of the process of the present invention.
Figs 8a to 8d are top view schematics representing the formation stages of an interwell communication zone between mobilized chambers of an array of SAGD well pairs and an in situ combustion sweep within the interwell communication zone in an underground reservoir according to an embodiment of the process of the present invention.
Fig 9 is a schematic section view of a laboratory experimental combustion tube showing the locations of core centerline, wall thermocouples and wall heaters.
Fig 10 is a simplified schematic of an experimental combustion tube set-up.
Fig 11 represents the core temperature profiles observed in the combustion tube of Fig 9 during the laboratory experimental combustion.
While the invention will be described in conjunction with example embodiments, it will be understood that it is not intended to limit the scope of the invention to these embodiments. On the contrary, it is intended to cover all alternatives, modifications and equivalents as may be included as defined by the appended claims.
DETAILED DESCRIPTION
The present invention provides an in situ process for recovering heavy hydrocarbons from an underground reservoir. By heavy hydrocarbons, it is meant heavy crude oils or bitumen, i.e. petroleum or petroleum-like liquids or semisolids occurring naturally in porous and fractured media. Bitumen deposits are also called tar sand, oil sand, oil-impregnated rock, bituminous sand and the like. In the following detailed description, the terms heavy hydrocarbons, oil/bitumen and bitumen will be used interchangeably. It is noted that in a preferred embodiment of the present invention, the in situ combustion process is performed in a bitumen containing reservoir.
In the first step, the process of the invention provides an array of well pairs for gravity controlled recovery of heavy hydrocarbons. Each well pair comprises a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well. It should be understood that the horizontal portions of the injection and production wells may have varying inclinations along their trajectory depending on the reservoir characteristics and the in situ process used to recover the hydrocarbons from the reservoir. In a preferred embodiment, the well pairs have a configuration for performing a SAGD
operation. It should also be noted that the well pairs may be configured and operated to perform a number of other in situ recovery processes during their lifetime whereby other mobilizing fluids are injected into the reservoir such as hot water, solvents, steam and mixtures thereof.
At least two well pairs are used in the process of the invention. However, for the purpose of illustrating the invention, reference will be made to three well pairs as shown in Figs 1 to 3, four well pairs as shown in Fig 4, two well pairs and an infill well as shown in Figs 5 and 6, and 5 well pairs as shown in Figs and 8.
Referring to Fig la, there is shown an underground reservoir 10 provided with three well pairs 12. Each well pair 12 comprises a fluid injection well 20, 22, 24 having a horizontal portion and a production well 30, 32, 34 having a horizontal portion positioned below and aligned with the horizontal portion of the injection well. The horizontal portions of the injection and production wells are connected to vertical portions (not illustrated) which extend to the surface where they are used to inject fluids underground or recover the produced fluids for further processing.
In the second and third steps of the process of the invention, as illustrated in Fig lb as well as in Figs 7a and 8a, the array of adjacent well pairs 12 is operated to inject steam or another mobilizing fluid via the injection wells 20, 22, 24 and to produce hydrocarbons from the production wells 30, 32, 34, thereby forming mobilized chambers 14 within the reservoir extending from each well pair 12. Fluid communication is then established between the mobilized chambers 14 of adjacent well pairs 12 to create an interwell communication zone 16 which is shown in Fig 1c and also in Figs 2a to 2d, 3a to 3c, 5a to 5d, 6a to 6c, 7b to 7d and 8b to 8d. In one embodiment, the start-up phase includes injection or circulation of hot water, steam or solvent into the injection well such that fluid communication is established in between the injection well and production well. The processing is then ramped up as steam is injected into the bitumen baring formation through the fluid injection well 20, 22, 24 and production fluid comprising heated mobilized bitumen and condensate is recovered from the lower parallel-running horizontal production well 30, 32, 34 respectively. What has been called a mobilized steam chamber 5 14 is developed, upward and outward from each well pair. As steam flows toward the perimeter of the chamber 14, it encounters the lower temperature of the formation and condenses, causing heating and mobilization of the heavy hydrocarbons which drain downwardly with the condensate toward the production well. In this way heat is transferred to the bitumen, causing the 10 bitumen to warm up to the point of mobilization or flow ability, preferably under gravity control. Eventually, both the bitumen and steam condensate are recovered from the formation through the production well 30, 32, 34 located below the steam injection well 20, 22, 24. As the heated and mobilized bitumen drains down, fresh bitumen becomes exposed at an extraction interface that is 15 subsequently heated by the ongoing steam contact and its condensation. The continuous drainage of bitumen from the formation results in the steam filled bitumen depleted extraction chamber growing toward the top of the formation and then spreading sideways over time. This chamber is called a SAGD steam chamber, a gravity drainage chamber or a mobilized chamber. In time, continuously injecting steam into the chambers leads to expanding the mobilized chambers to the point of establishing fluid communication between the mobilized chambers of adjacent well pairs and creates an interwell communication zone 16. In other words, the chambers 14 coalesce to form a larger chamber where the well pairs 12 are in fluid communication with each other. Referring to Fig 7b, the interwell communication zone 16 preferably includes the individual mobilized chambers 14 of the entire array of SAGD well pairs 12. In typical SAGD operation, the interwell communication zone may usually have a porosity of between about 0.30 to about 0.35. More regarding the interwell communication zone 16 will be described herein-below in reference to Figs 8a-8d. When SAGD operation reaches the economic limit, usually when bitumen recovery factor is at least 50% of the original bitumen in place or SAGD recoverable reserve, steam injection is terminated. One can then say that the SAGD operation is mature. The temperature in the mature SAGD chambers is generally around about 190 C to about 257 C, which is based on the SAGD operating pressure from 1300kPa to 4500kPa. However, a temperature of at least above 150 C, and even more preferably above 200 C, is favourable for the next steps of the process of the invention including initiating in situ combustion in the mature SAGD chamber. Furthermore, residual hydrocarbons are still present in and around the mobilized chambers after SAGD operation, which will also favour combustion. In another optional aspect, the bitumen residual saturation in a mature SAGD chamber may be about 0.20 to less than about 0.05.
Referring to Figs 2a to 2d, there is shown the following steps of the process of the invention and more particularly those steps which allow recovering further oil/bitumen from the underground reservoir 10. As more particularly shown in Fig 2a, an oxidizing gas, e.g. oxygen or air, preferably air for availability and economic reasons is injected through a well, preferably through one of the fluid injecting wells 20 into the mature interwell chamber 16. Even though air is preferably injected in the process of the invention, it is also possible to inject other gases such as methane (e.g. pipelined methane), fuel gas (e.g. fuel gas from steam boiler), pure oxygen or enriched air (e.g. an oxygen concentration above 21%) as oxidizing gas and it is also possible to inject or co-inject additional gases at various steps of the process such as CO2 or N2, recovered flue gases from a previous combustion cycle, and the like. A mixture of water and air could also be used. Injection of a mixture steam/air is also possible.
In this latter case, the mole ratio of air to steam in this mixture is preferably more than 2%.
In another optional aspect, the air injection rate is based on the value of air required and of the minimum air flux to sustain in situ combustion. The minimum air flux is dependent upon the formation thickness, well length and well spacing. The injection rate is also dependent on the operating pressure and reservoir pressure. For example, for a typical SAGD well configuration and Athabasca bitumen formation, this rate may be estimated to be around 10,000 m3(ST)/day/well to 100,000 m3(ST)/day/well. In a preferred embodiment, the oxidizing gas injection flux may be about 3 to about 1.2 m3(ST)/m2.hour.
While it is preferred to convert one of the existing wells into the oxidizing gas injection well, it is also possible to provide an additional well, which may be vertical or horizontal, as the oxygen injection well. Due to the high temperature in the chamber and the presence of residual hydrocarbons, ignition occurs spontaneously and a combustion region forms around injecting well 20. It is worth noting that even though ignition is generally spontaneous, it would also be possible to initiate combustion through introduction of a source of ignition at the injection well. It is also possible to promote initial combustion by injecting a high oxygen content gas and then gradually scaling back oxygen content to the composition of air. At this step of initiating combustion, the producer well below the converted oxidizing gas injection well 20 is shut in while all the other wells (injectors and producers) 22, 32, 24 and 34 are preferably left open in production mode. The combustion region is then allowed to propagate through the interwell communication zone 16 encouraged in the direction of adjacent well pairs of the array as a result of pressure differential between the air injector 20 and the open wells 22, 32, 24 and 34. Injection of oxidizing gas is continued and when the first breakthrough of heat, combustion flue gases occurs at wells 22 and 32, or in response to another detected process parameter, these wells are restricted by choking or shutting in. For example, referring to Fig 2b, the well 22 is shut in upon arrival of the combustion front, while the downstream wells 24 and 34 are kept open to continue encouraging the combustion front to progress further along the interwell chamber 16. The timed restriction of the wells causes the advancing combustion front from prematurely breaking through and enables a continued advancement of the combustion across more of the interwell chamber. The combustion front is redirected toward the remaining open wells 24 and 34. In this way, the well pairs are operated such that each subsequent downstream well is choked or shut in upon arrival of the combustion front thus promoting the advancement of the combustion across and throughout the interwell region. Once the oxygen/combustion front is close to the last well pair, wells 24 and 34 in Fig 2c for example, the restriction procedure is applied to these wells. Fig 2c shows all wells being shut in except for the air injection well. Continuing air injection causes the reservoir pressure to rise till a desired pressure value. Then, air injection is terminated and that well may also be shut in. The pressure-up shut-in time may be provided to allow prolonged heating of the interwell chamber.
Even though Figs 2a to 2d only shows three well pairs, it should be understood that more well pairs could be present in the array and in the mature interwell chamber. The pressure-up phase could also be implemented sequentially until all the further wells are restricted.
Preferably, the pressure-up phase is reached by restricting production by either choking or shutting in wells 22, 32, 24 and 34, after oxygen or combustion front has arrived to these producer wells, while air is being injected. This results in pressure rising both in the mature SAGD chamber and its surrounding reservoir, especially in the upswept area. Thus, combustion front is forced to penetrate from the mature SAGD chamber into the adjacent portion of the reservoir which is upswept by steam and colder and which has a higher remaining oil/bitumen saturation. Therefore, more oxygen is consumed rather than flow breakthrough through the mature chamber that connected air injector 20 and wells 22, 32, 24 and 34. Thereby, more oil/bitumen is heated and eventually mobilized.
It is also worth mentioning that high energy can be released from the combustion or oxidation, and local combustion zone temperature can reach 300 C or more. Flue gases (mainly containing nitrogen and carbon dioxide) are generated as a result of these high temperature oxidation or combustion reactions, which displace and mobilize residual oil/bitumen to form oil/bitumen banks between the well pairs. Also, flue gas occupies the void volume which is left by the steam condensate, so as to allow gravity drainage to continuously take place within the mature chamber, and incremental oil/bitumen is recovered.
Once the desired value of chamber pressure is reached, e.g. at a pressure below 4500 kPa, oxidizing gas or air injection is terminated. The next step of the process comprises a blowdown/production phase. Fig 2d illustrates this phase of the process. In one preferred aspect, the air injector 20 is shut in and eventually converted into a producer. Wells 30, 22, 32, 24, and 34 are also converted into producers in this period. It should be noted that depending on the reservoir conditions and oil/bitumen content as well as the economics of production, it may be preferred to open only the original production wells 30, and 34 at the blowdown/production stage. The producers are preferably opened with little or no restriction, and the heated and mobilized oil/bitumen flows in the channels and is collected by the producers. The blowdown/production phase is continued until the oil/bitumen production rate falls off to a given limit, for example above 500 kPa bottom hole pressure of the production wells 30, 32 and 34. At the end of the blowdown/production phase, the oil/bitumen remaining in the mature chamber preferably ensures that ignition and combustion is obtained during the next oxidizing gas injection or pressure-up cycle.
Fig 2d shows that well 20, that is used as an oxidizing gas injection well during the injection cycle, can also be converted into a producer to collect flue gas and bitumen when blowdown/production phase is taken place. However, this well could also be simply shut in during blowdown/production phase and be re-used for injecting oxidizing gas or air in the next pressure-up phase.
In a preferred aspect of the present invention, the oxidizing injection pressure-up and blowdown/production sequence is repeated cyclically, for instance until the oil/bitumen production rate falls off to a given economic limit or until the residual bitumen in the reservoir is insufficient to support the initiation or adequate sweep of combustion.
In another optional aspect, the flue gases and liquids (oil/bitumen) are produced through the producers at the end of a cycle.
Figs 2a to 2d illustrate an embodiment of the process of the invention wherein a configuration of three well pairs is used, in which steam injector 20, that is the injector of the well pair of one far end of the array, is converted into oxidizing gas injector during the pressure-up phase. In this preferred scenario, the in situ 5 combustion sweep is able to advance across the entire distance of the interwell chamber, heating and mobilizing residual bitumen in a continuous sweep.
However, many other configurations and operational variations could be used to implement the process of the present invention. Some other possible configurations will be discussed hereinafter. However, the process of the 10 invention is not limited to these specific examples.
In Figs 3a to 3d, for example, the steam injector of a well pair, in between two other well pairs, is converted into the oxidizing gas injector. Thus, air is injected through well 22 and combustion is initiated in the vicinity of this well (Fig 3a).
Well 32 below well 22 is shut in and the combustion region is then allowed to 15 propagate through the interwell communication zone 16 in the direction of adjacent well pairs as a result of pressure differential between the air injector 22 and the open wells 20, 30, 24 and 34. Thus, the combustion region moves in two opposite directions. Injection of oxidizing gas is continued and when the first breakthrough of heat/combustion occurs at wells 20 and 24, and 30 and 20 34, these wells are restricted by choking or shutting in (see Fig 3b). Air injection is continued and the reservoir's pressure is allowed to rise until the desired pressure value (Fig 3c). Then, air injection is terminated. The pressure-up phase is then followed by the blowdown phase wherein preferably all wells 20, 22, 24, 30, 32, 34, or selected wells amongst those, are opened and bitumen is produced (see Fig 3d). The pressure-up/blowdown sequence is then repeated to recover further bitumen.
Figs 4a and 4b show two other possible configurations of the well pairs used to implement the process according to another embodiment of the invention. In this case, four well pairs are represented.
In Fig 4a, the injector of the first well pair from the array is used as the air injector and all the other wells are used as producers. Combustion is initiated in the vicinity of the injector while the producer just below is shut in. All the other wells are opened and the combustion front is allowed to propagate in the direction of the second well pair. When the first breakthrough of heat, combustion and/or gas occurs at the second well pair, its wells are restricted.
Oxidizing gas or air injection is continued and the reservoir's pressure is allowed to rise. The combustion front is redirected toward the remaining opened wells of the third and fourth well pairs. Once the combustion front is close to the third well pair, the restriction procedure is re-applied to its wells.
Continuing oxidizing gas or air injection will allow the combustion front to finally propagate toward the fourth well pair wherein the wells are still opened. Once the combustion front reaches the fourth well pair, its wells are shut in, air injection is continued and the reservoir's pressure is allowed to rise till the desired pressure value. Oxidizing gas or air injection is then terminated and the blowdown phase is implemented wherein all wells, or selected wells, are opened and bitumen is produced there-from. The pressure-up/blowdown sequence is then repeated to recover further bitumen.
Fig 4b represents the case when air is injected through two different wells.
For example, two steam injectors of SAGD well pairs may be converted to air injectors in the process of the present invention. In this example, air is injected in the steam injector of the first well pair of the array and in the steam injector of the third well pair. The remaining wells are used as producers. In this configuration, combustion is initiated both in the vicinity of the first and third injectors while the producer below in their respective pair is shut in. The first combustion front moves from the first well pair in the direction of the second well pair where the wells are opened. The second combustion front moves from the third well pair in two directions, toward the second well pair and also toward the fourth well pair, the wells of both these pair wells being also opened.
Before the combustion fronts reach the second and fourth well pairs, the producers at these pairs are shut in. Air injection is continued to pressure-up the chamber.
Then, the blowdown phase is implemented by opening the wells and the oil/bitumen is produced.
Fig 2d shows that well 20, that is used as an oxidizing gas injection well during the injection cycle, can also be converted into a producer to collect flue gas and bitumen when blowdown/production phase is taken place. However, this well could also be simply shut in during blowdown/production phase and be re-used for injecting oxidizing gas or air in the next pressure-up phase.
In a preferred aspect of the present invention, the oxidizing injection pressure-up and blowdown/production sequence is repeated cyclically, for instance until the oil/bitumen production rate falls off to a given economic limit or until the residual bitumen in the reservoir is insufficient to support the initiation or adequate sweep of combustion.
In another optional aspect, the flue gases and liquids (oil/bitumen) are produced through the producers at the end of a cycle.
Figs 2a to 2d illustrate an embodiment of the process of the invention wherein a configuration of three well pairs is used, in which steam injector 20, that is the injector of the well pair of one far end of the array, is converted into oxidizing gas injector during the pressure-up phase. In this preferred scenario, the in situ 5 combustion sweep is able to advance across the entire distance of the interwell chamber, heating and mobilizing residual bitumen in a continuous sweep.
However, many other configurations and operational variations could be used to implement the process of the present invention. Some other possible configurations will be discussed hereinafter. However, the process of the 10 invention is not limited to these specific examples.
In Figs 3a to 3d, for example, the steam injector of a well pair, in between two other well pairs, is converted into the oxidizing gas injector. Thus, air is injected through well 22 and combustion is initiated in the vicinity of this well (Fig 3a).
Well 32 below well 22 is shut in and the combustion region is then allowed to 15 propagate through the interwell communication zone 16 in the direction of adjacent well pairs as a result of pressure differential between the air injector 22 and the open wells 20, 30, 24 and 34. Thus, the combustion region moves in two opposite directions. Injection of oxidizing gas is continued and when the first breakthrough of heat/combustion occurs at wells 20 and 24, and 30 and 20 34, these wells are restricted by choking or shutting in (see Fig 3b). Air injection is continued and the reservoir's pressure is allowed to rise until the desired pressure value (Fig 3c). Then, air injection is terminated. The pressure-up phase is then followed by the blowdown phase wherein preferably all wells 20, 22, 24, 30, 32, 34, or selected wells amongst those, are opened and bitumen is produced (see Fig 3d). The pressure-up/blowdown sequence is then repeated to recover further bitumen.
Figs 4a and 4b show two other possible configurations of the well pairs used to implement the process according to another embodiment of the invention. In this case, four well pairs are represented.
In Fig 4a, the injector of the first well pair from the array is used as the air injector and all the other wells are used as producers. Combustion is initiated in the vicinity of the injector while the producer just below is shut in. All the other wells are opened and the combustion front is allowed to propagate in the direction of the second well pair. When the first breakthrough of heat, combustion and/or gas occurs at the second well pair, its wells are restricted.
Oxidizing gas or air injection is continued and the reservoir's pressure is allowed to rise. The combustion front is redirected toward the remaining opened wells of the third and fourth well pairs. Once the combustion front is close to the third well pair, the restriction procedure is re-applied to its wells.
Continuing oxidizing gas or air injection will allow the combustion front to finally propagate toward the fourth well pair wherein the wells are still opened. Once the combustion front reaches the fourth well pair, its wells are shut in, air injection is continued and the reservoir's pressure is allowed to rise till the desired pressure value. Oxidizing gas or air injection is then terminated and the blowdown phase is implemented wherein all wells, or selected wells, are opened and bitumen is produced there-from. The pressure-up/blowdown sequence is then repeated to recover further bitumen.
Fig 4b represents the case when air is injected through two different wells.
For example, two steam injectors of SAGD well pairs may be converted to air injectors in the process of the present invention. In this example, air is injected in the steam injector of the first well pair of the array and in the steam injector of the third well pair. The remaining wells are used as producers. In this configuration, combustion is initiated both in the vicinity of the first and third injectors while the producer below in their respective pair is shut in. The first combustion front moves from the first well pair in the direction of the second well pair where the wells are opened. The second combustion front moves from the third well pair in two directions, toward the second well pair and also toward the fourth well pair, the wells of both these pair wells being also opened.
Before the combustion fronts reach the second and fourth well pairs, the producers at these pairs are shut in. Air injection is continued to pressure-up the chamber.
Then, the blowdown phase is implemented by opening the wells and the oil/bitumen is produced.
It should also be noted that the process may be implemented by injecting oxidizing gas such as air through two injectors of adjacent well pairs (see Fig 4c). In this case, oxidizing gas such as air is injected in the steam injector of the second and third well pair of the array. The composition of the oxidizing gas injected through the two wells may be the same or different and may contain one or more of the above mentioned gases. The remaining wells are used as producers. In this configuration, combustion is initiated both in the vicinity of the second and third injectors while the producer below in their respective pair is shut in. A first combustion front moves from the second well pair in the direction of the first well pair of the array where the wells are opened. A second combustion front moves from the third well pair in the direction of the fourth well pair of the array where the wells are also opened. Before the combustion fronts reach the first and fourth well pairs, the producers at these pairs are shut in. Air injection is continued to pressure-up the chamber. Then, the blowdown phase is implemented by opening the wells and the oil/bitumen is produced.
In another optional aspect, referring to Figs 5a to 5d, 6a to 6d and 7a to 7d, one or more infill wells may each be provided in between adjacent well pairs and may be involved in the in situ combustion process of the present invention.
Infill wells may be used to help recover stranded bitumen between SAGD well pairs. The infill wells may be provided by drilling a simple horizontal well between two existing well pairs in the bypassed zone of stranded or bypassed bitumen. Remaining mobilized bitumen is collected through this infill well.
The process of the present invention may also be implemented in an underground reservoir further comprising one or more infill wells. One or more of the infill wells may then be used as a producer or it could be used as an air injector.
In Figs 5a to 5d, there is shown a two well pair configuration wherein an infill well 40 is present in between the two pairs. The infill well 40 is used as a producer, but it should be understood that it may also be initially used as an injection of steam, hot water and/or solvent to help mobilized the surrounding bitumen. In one aspect, combustion is initiated at well 20, while well 30 below is shut in. Infill well 40 and wells 22 and 32 are preferably opened at this stage (Fig 5a). The combustion front then propagates through the interwell chamber in the direction of infill well 40 Injection of air is continued and before combustion front reaches the infill well 40, the latter is restricted by choking or shutting in (see Fig 5b). The restriction of the infill well 40 causes the combustion front to be redirected toward the remaining opened wells 22 and 32. Once the combustion front is close to wells 22 and 32, the restriction procedure is re-applied to these wells. Continuing air injection causes the reservoir pressure to rise to a given pressure value (see Fig 5c). Then, air injection is terminated. The blowdown phase is then implemented by opening all of the wells or selected wells (see Fig 5d).
Figs 6a to 6d show another alternative wherein an infill well 40 is used as the air injector. In this case, the combustion region formed in the vicinity of the infill well 40 is allowed to move in the direction of both adjacent well pairs wherein wells 20, 30, 22, 32 are opened (see Figs 6a-6b). Injection of air is continued and before combustion front reaches wells 20, 30, 22, 32, these are restricted by choking or shutting in. Oxidizing gas or air injection is continued and the reservoir's pressure is allowed to rise (see Fig 6c). Then, air injection is terminated. Then follows the blowdown phase wherein all wells or selected wells, are opened and bitumen is collected (Fig 6d).
Referring now to Figs 7c and 7d, the SAGD array of well pairs may be provided with at least one infill well in between each adjacent well pair. Preferably, there is one infill well in between each adjacent well pair, but there may be multiple infill wells in one or more cases, depending on the size of the bypassed region, the distance in between adjacent well pairs as well as reservoir characteristics.
In one aspect, conducting in situ combustion heats one or more bypassed regions in which the infill wells have not yet established fluid communication with the coalesced mobilized chamber, e.g. infill wells 40' in Fig 7d.
Referring to Figs 8a to 8d, the development of the mobilized chambers 14 and the interwell communication zone 16 may occur in a variety of ways and the process of the present invention may be implemented in accordance with mobilized chamber development. For instance, in one aspect, the in situ combustion process may be implemented once the interwell chamber 16 covers the majority or entirety of the area above the array of well pairs.
This implementation enables the combustion front to advance so as to remain generally parallel with the well pairs in a direction that is generally perpendicular with respect to the well pairs, as shown in Fig 8d. This promotes consistency and predictability in operation of the in situ combustion process.
In another optional aspect, the combustion may be conducted while the interwell chamber has not yet completely covered the area above and between all well pairs, e.g. as shown in Fig 8b. In this case, the SAGD reservoir still includes some immobile bitumen regions 42 which are mainly located in between adjacent well pairs. As can be seen referring to Figs 8b and 8c, larger immobile bitumen regions 42a may eventually in time reduce to a smaller immobile bitumen region 42b and eventually this small region may be heated up resulting in sufficiently reducing the viscosity of bitumen and make the bitumen mobilized. In an optional aspect, the in situ combustion may be conducted while there are still various immobile bitumen regions 42 above and between the well pairs and the combustion sweeps help to heat, mobilize and reduce the size of these less mobile bitumen regions 42, compared to the SAGD
chamber. In such cases, the combustion front follows a more tortuous path, which may have certain upsides.
As described above, the process includes cyclically conducting the in situ combustion sweep and blowdown recovery. In one aspect, each cycle uses the same well as the oxygen injection well and the combustion displacement pattern is generally similar with each cycle. This may present various advantages, for example reducing well conversion requirements and having consistent combustion patterns and development over multiple cycles.
Alternatively, different cycles may use different wells as the oxygen injection well. In one such scenario, a well at one end of the array is used as the oxygen injection well for one cycle and a well at the opposite end of the array is used as the oxygen injection well for a subsequent cycle. The oxidizing gas or air injection may be alternated back and forth between two wells at either end of the array. The cycles may also use a central well as the oxygen injection well followed by outside end well in subsequent cycles. Such back-and-forth or alternating oxygen injection techniques may present advantages by promoting different combustion sweep patterns and directions to enhance bitumen 5 mobilization, improve thorough bitumen recovery from more areas of the interwell chamber and investigate the combustion efficiency and productivity according to different combustion flows.
The above description and drawings are intended to help the understanding of the invention rather than to limit its scope. It will be apparent to one skilled in 10 the art that various modifications may be made to the invention without departing from what has actually been invented.
EXAMPLES
Combustion tests were performed on a bitumen core matrix to assess the suitability for air injection based on enhanced oil recovery process at low 15 bitumen saturations in conditions that would be encountered in a steamed region after a SAGD operation is mature. The core materials were taken from the native reservoir of Suncor's Firebag SAGD operation site, about 270 m to 310 m underground.
The Firebag reservoir bitumen-native core was packed in a combustion tube as 20 illustrated in Fig 9. The core has been established residual oil saturation around only 8.0 % to mimic the case of residual bitumen within a SAGD
chamber after SAGD operation.
This experiment was designed to investigate the feasibility of the process of the invention, by showing that, using air injection, combustion can be ignited 25 automatically, combustion front can be sustained, and bitumen can be recovered from a mature SAGD chamber.
The overall burning characteristics using dry air injection of the native core-bitumen-brine premix at reservoir pressure of 1500 kPag and reservoir temperature of 190 C were assessed. The air and fuel requirements and other gas phase parameters were measured. Produced gas compositions and produced oil and water properties were measured to provide benchmarks for monitoring the process and field operations.
On completion of the packing operation, the tube was sealed, insulated and inserted into the pressure jacket. Fig. 10 shows a simplified schematic of the combustion tube set-up. Table 1 gives the average properties of the composite core prior to the test and the fluid saturations at the start of air injection.
Table 1: Properties of initial core pack and at ignition Permeability (darcies) Not Measured Calculated Porosity (%) 38.9 Mass of Liquids Present Prior to Start of After Inert Gas Flood (grams) Inert Gas Flood (Start of Air Injection) Oil in Core 437.3 437.3 Water in Core 3868.2 1896.8 Oil in Lines 0.0 0.0 Water in Lines 456.0 50.0 Oil in Total System 437.3 437.3 Water in Total System 4324.2 1946.8 Core Saturations (Volume %) Oil 8.0 8.0*
Brine 68.9 33.8*
Gas 23.1 58.2*
* Core Saturations at the start of air injection are based on densities at 25 C and atmospheric pressure. They should fairly accurately represent the core saturations at the actual conditions of 190 C and 1500 kPag (218 psig). The gas saturation is by difference.
The experimental results indicate that the bitumen-native core can be ignited automatically at an initial temperature of 200 C, which is after steam injection.
The combustion front advanced smoothly through the core. The temperature profiles are shown in Figure 11. The temperature response following the start of air injection indicated a good ignition, and shortly after the ignition, the wall heaters were set to adiabatic control with a temperature lag behind the centerline temperature. The combustion front progressed stably through the core pack.
The following is a summary of the conditions and results of the experiments:
Operating conditions:
- Core Porosity: 38.9 percent (calculated) - Core Permeability: Not measured - Pressure: 1500kPag (218 psig) - Pre-heat Temperature: 190 C
- Feed Gas: Normal air (21.14 mole percent oxygen, balance nitrogen) - Initial Injection Air Flux: 30.0 m3(ST)/m2h - Oil Saturation: 8.0 percent - The rest of fluid saturations are balanced with water and steam vapour.
Combustion parameters for the overall test:
- A maximum recorded peak temperature of 640 C
- An overall fuel requirement of 17.3 kg/m3 - An overall apparent atomic hydrogen to carbon ratio of 1.14 The combustion process, occurring in this post-SAGD case, that followed the core ignition consumed 49.1% of the initial bitumen in place to mobilise 13.9%
of the initial oil and effectively displaced almost all of the initial water.
Residual bitumen remained in the unburned section of the core.
Table 2 shows the stabilized product gas compositions of the test results. The results show that combustion stabilization occurs following air injection into a mature SAGD chamber.
Table 2: Stable Product Gas Composition Component Mole % (2.45-7.15 hours)*
CO2 14.09 CO 4.61 02 0.13 N2 80.50 CH4 0.15 C2H4 0.03 C2H6 0.05 C3H6 0.07 C3H8 0.05 C4+ 0.13 H2S 0.15 H2 0.04 *Stabilized time by the front is 0.65-8.92 hours
In another optional aspect, referring to Figs 5a to 5d, 6a to 6d and 7a to 7d, one or more infill wells may each be provided in between adjacent well pairs and may be involved in the in situ combustion process of the present invention.
Infill wells may be used to help recover stranded bitumen between SAGD well pairs. The infill wells may be provided by drilling a simple horizontal well between two existing well pairs in the bypassed zone of stranded or bypassed bitumen. Remaining mobilized bitumen is collected through this infill well.
The process of the present invention may also be implemented in an underground reservoir further comprising one or more infill wells. One or more of the infill wells may then be used as a producer or it could be used as an air injector.
In Figs 5a to 5d, there is shown a two well pair configuration wherein an infill well 40 is present in between the two pairs. The infill well 40 is used as a producer, but it should be understood that it may also be initially used as an injection of steam, hot water and/or solvent to help mobilized the surrounding bitumen. In one aspect, combustion is initiated at well 20, while well 30 below is shut in. Infill well 40 and wells 22 and 32 are preferably opened at this stage (Fig 5a). The combustion front then propagates through the interwell chamber in the direction of infill well 40 Injection of air is continued and before combustion front reaches the infill well 40, the latter is restricted by choking or shutting in (see Fig 5b). The restriction of the infill well 40 causes the combustion front to be redirected toward the remaining opened wells 22 and 32. Once the combustion front is close to wells 22 and 32, the restriction procedure is re-applied to these wells. Continuing air injection causes the reservoir pressure to rise to a given pressure value (see Fig 5c). Then, air injection is terminated. The blowdown phase is then implemented by opening all of the wells or selected wells (see Fig 5d).
Figs 6a to 6d show another alternative wherein an infill well 40 is used as the air injector. In this case, the combustion region formed in the vicinity of the infill well 40 is allowed to move in the direction of both adjacent well pairs wherein wells 20, 30, 22, 32 are opened (see Figs 6a-6b). Injection of air is continued and before combustion front reaches wells 20, 30, 22, 32, these are restricted by choking or shutting in. Oxidizing gas or air injection is continued and the reservoir's pressure is allowed to rise (see Fig 6c). Then, air injection is terminated. Then follows the blowdown phase wherein all wells or selected wells, are opened and bitumen is collected (Fig 6d).
Referring now to Figs 7c and 7d, the SAGD array of well pairs may be provided with at least one infill well in between each adjacent well pair. Preferably, there is one infill well in between each adjacent well pair, but there may be multiple infill wells in one or more cases, depending on the size of the bypassed region, the distance in between adjacent well pairs as well as reservoir characteristics.
In one aspect, conducting in situ combustion heats one or more bypassed regions in which the infill wells have not yet established fluid communication with the coalesced mobilized chamber, e.g. infill wells 40' in Fig 7d.
Referring to Figs 8a to 8d, the development of the mobilized chambers 14 and the interwell communication zone 16 may occur in a variety of ways and the process of the present invention may be implemented in accordance with mobilized chamber development. For instance, in one aspect, the in situ combustion process may be implemented once the interwell chamber 16 covers the majority or entirety of the area above the array of well pairs.
This implementation enables the combustion front to advance so as to remain generally parallel with the well pairs in a direction that is generally perpendicular with respect to the well pairs, as shown in Fig 8d. This promotes consistency and predictability in operation of the in situ combustion process.
In another optional aspect, the combustion may be conducted while the interwell chamber has not yet completely covered the area above and between all well pairs, e.g. as shown in Fig 8b. In this case, the SAGD reservoir still includes some immobile bitumen regions 42 which are mainly located in between adjacent well pairs. As can be seen referring to Figs 8b and 8c, larger immobile bitumen regions 42a may eventually in time reduce to a smaller immobile bitumen region 42b and eventually this small region may be heated up resulting in sufficiently reducing the viscosity of bitumen and make the bitumen mobilized. In an optional aspect, the in situ combustion may be conducted while there are still various immobile bitumen regions 42 above and between the well pairs and the combustion sweeps help to heat, mobilize and reduce the size of these less mobile bitumen regions 42, compared to the SAGD
chamber. In such cases, the combustion front follows a more tortuous path, which may have certain upsides.
As described above, the process includes cyclically conducting the in situ combustion sweep and blowdown recovery. In one aspect, each cycle uses the same well as the oxygen injection well and the combustion displacement pattern is generally similar with each cycle. This may present various advantages, for example reducing well conversion requirements and having consistent combustion patterns and development over multiple cycles.
Alternatively, different cycles may use different wells as the oxygen injection well. In one such scenario, a well at one end of the array is used as the oxygen injection well for one cycle and a well at the opposite end of the array is used as the oxygen injection well for a subsequent cycle. The oxidizing gas or air injection may be alternated back and forth between two wells at either end of the array. The cycles may also use a central well as the oxygen injection well followed by outside end well in subsequent cycles. Such back-and-forth or alternating oxygen injection techniques may present advantages by promoting different combustion sweep patterns and directions to enhance bitumen 5 mobilization, improve thorough bitumen recovery from more areas of the interwell chamber and investigate the combustion efficiency and productivity according to different combustion flows.
The above description and drawings are intended to help the understanding of the invention rather than to limit its scope. It will be apparent to one skilled in 10 the art that various modifications may be made to the invention without departing from what has actually been invented.
EXAMPLES
Combustion tests were performed on a bitumen core matrix to assess the suitability for air injection based on enhanced oil recovery process at low 15 bitumen saturations in conditions that would be encountered in a steamed region after a SAGD operation is mature. The core materials were taken from the native reservoir of Suncor's Firebag SAGD operation site, about 270 m to 310 m underground.
The Firebag reservoir bitumen-native core was packed in a combustion tube as 20 illustrated in Fig 9. The core has been established residual oil saturation around only 8.0 % to mimic the case of residual bitumen within a SAGD
chamber after SAGD operation.
This experiment was designed to investigate the feasibility of the process of the invention, by showing that, using air injection, combustion can be ignited 25 automatically, combustion front can be sustained, and bitumen can be recovered from a mature SAGD chamber.
The overall burning characteristics using dry air injection of the native core-bitumen-brine premix at reservoir pressure of 1500 kPag and reservoir temperature of 190 C were assessed. The air and fuel requirements and other gas phase parameters were measured. Produced gas compositions and produced oil and water properties were measured to provide benchmarks for monitoring the process and field operations.
On completion of the packing operation, the tube was sealed, insulated and inserted into the pressure jacket. Fig. 10 shows a simplified schematic of the combustion tube set-up. Table 1 gives the average properties of the composite core prior to the test and the fluid saturations at the start of air injection.
Table 1: Properties of initial core pack and at ignition Permeability (darcies) Not Measured Calculated Porosity (%) 38.9 Mass of Liquids Present Prior to Start of After Inert Gas Flood (grams) Inert Gas Flood (Start of Air Injection) Oil in Core 437.3 437.3 Water in Core 3868.2 1896.8 Oil in Lines 0.0 0.0 Water in Lines 456.0 50.0 Oil in Total System 437.3 437.3 Water in Total System 4324.2 1946.8 Core Saturations (Volume %) Oil 8.0 8.0*
Brine 68.9 33.8*
Gas 23.1 58.2*
* Core Saturations at the start of air injection are based on densities at 25 C and atmospheric pressure. They should fairly accurately represent the core saturations at the actual conditions of 190 C and 1500 kPag (218 psig). The gas saturation is by difference.
The experimental results indicate that the bitumen-native core can be ignited automatically at an initial temperature of 200 C, which is after steam injection.
The combustion front advanced smoothly through the core. The temperature profiles are shown in Figure 11. The temperature response following the start of air injection indicated a good ignition, and shortly after the ignition, the wall heaters were set to adiabatic control with a temperature lag behind the centerline temperature. The combustion front progressed stably through the core pack.
The following is a summary of the conditions and results of the experiments:
Operating conditions:
- Core Porosity: 38.9 percent (calculated) - Core Permeability: Not measured - Pressure: 1500kPag (218 psig) - Pre-heat Temperature: 190 C
- Feed Gas: Normal air (21.14 mole percent oxygen, balance nitrogen) - Initial Injection Air Flux: 30.0 m3(ST)/m2h - Oil Saturation: 8.0 percent - The rest of fluid saturations are balanced with water and steam vapour.
Combustion parameters for the overall test:
- A maximum recorded peak temperature of 640 C
- An overall fuel requirement of 17.3 kg/m3 - An overall apparent atomic hydrogen to carbon ratio of 1.14 The combustion process, occurring in this post-SAGD case, that followed the core ignition consumed 49.1% of the initial bitumen in place to mobilise 13.9%
of the initial oil and effectively displaced almost all of the initial water.
Residual bitumen remained in the unburned section of the core.
Table 2 shows the stabilized product gas compositions of the test results. The results show that combustion stabilization occurs following air injection into a mature SAGD chamber.
Table 2: Stable Product Gas Composition Component Mole % (2.45-7.15 hours)*
CO2 14.09 CO 4.61 02 0.13 N2 80.50 CH4 0.15 C2H4 0.03 C2H6 0.05 C3H6 0.07 C3H8 0.05 C4+ 0.13 H2S 0.15 H2 0.04 *Stabilized time by the front is 0.65-8.92 hours
Claims (69)
1. An in situ process for recovering heavy hydrocarbons from an underground reservoir, comprising:
a) providing an array of well pairs for gravity controlled recovery of heavy hydrocarbons, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well;
b) operating the array of adjacent well pairs to produce hydrocarbons from the production wells and forming mobilized chambers within the reservoir extending from corresponding well pairs;
c) establishing fluid communication between the mobilized chambers of adjacent ones of the well pairs to create an interwell mobilized zone;
d) operating at least one well as an oxidizing gas injection well;
e) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
f) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
g) regulating the array of well pairs to pressurize the interwell communication zone;
h) regulating the array of well pairs to effectuate blowdown and produce a blowdown portion of the heavy hydrocarbons therefrom;
and i) cyclically repeating steps d) to h).
a) providing an array of well pairs for gravity controlled recovery of heavy hydrocarbons, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well;
b) operating the array of adjacent well pairs to produce hydrocarbons from the production wells and forming mobilized chambers within the reservoir extending from corresponding well pairs;
c) establishing fluid communication between the mobilized chambers of adjacent ones of the well pairs to create an interwell mobilized zone;
d) operating at least one well as an oxidizing gas injection well;
e) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
f) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
g) regulating the array of well pairs to pressurize the interwell communication zone;
h) regulating the array of well pairs to effectuate blowdown and produce a blowdown portion of the heavy hydrocarbons therefrom;
and i) cyclically repeating steps d) to h).
2. The process of claim 1, wherein step d) comprises converting a fluid injection well into the oxidizing gas injection well.
3. The process of claim 2, comprising operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
4. The process of claim 3, wherein the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
5. The process of any one of claims 1 to 4, wherein step f) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
6. The process of claim 5, wherein both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
7. The process of claim 5 or 6, wherein both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
8. The process of any one of claims 5 to 7, wherein the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
9. The process of any one of claims 5 to 7, wherein the restricting of each of the well pairs is performed upon breakthrough of combustion gas there-through.
10. The process of any one of claims 1 to 9, wherein step g) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
11. The process of any one of claims 1 to 10, wherein step h) comprises operating at least one of the wells of the array of well pairs in production mode.
12. The process of any one of claims 1 to 11, wherein step h) comprises operating the production wells in production mode.
13. The process of any one of claims 1 to 12, wherein step h) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
14. The process of any one of claims 1 to 13, wherein the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
15. The process of any one of claims 1 to 14, wherein the underground reservoir is further provided with at least one infill well positioned in between two adjacent well pairs.
16. The process of claim 15, wherein step c) comprises establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
17. The process of claim 15 or 16, wherein step d) comprises converting the infill well into the oxidizing gas injection well.
18. The process of any one of claims 15 to 17, wherein step f) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward; and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward; and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
19. The process of claim 18, wherein each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
20. The process of any one of claims 15 to 19, wherein step g) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
21. The process of any one of claims 15 to 20, wherein step h) comprises operating each of the at least one infill well in production mode.
22. The process of any one of claims 1 to 21, wherein step i) comprises selecting the same well as the oxidizing gas injection well for each cycle.
23. The process of any one of claims 1 to 21, wherein step i) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
24. The process of any one of claims 1 to 23, wherein a single well is used as the oxidizing gas injection well.
25. The 'process of any one of claims 1 to 24, wherein the oxidizing gas injection well is on one end of the interwell communication zone.
26. The process of claim 25, wherein the oxidizing gas injection well is the injection well of an outside one of the well pairs.
27. The process of claim 25 or 26, wherein the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
28. The process of claim 27, wherein the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
29. A cyclic in situ combustion method for a mature steam assisted gravity drainage (SAGD) operation in an underground reservoir, the mature SAGD
operation comprising an array of well pairs generally parallel to each other and an interwell communication zone between the well pairs, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well, the cyclic in situ combustion method comprising:
(i) operating at least one well as an oxidizing gas injection well;
(ii) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(iii) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(iv) pressurizing the interwell communication zone;
(v) producing a blowdown portion of the heavy hydrocarbons therefrom; and (vi) cyclically repeating steps (i) to (v).
operation comprising an array of well pairs generally parallel to each other and an interwell communication zone between the well pairs, each well pair comprising a fluid injection well having a horizontal portion and a production well having a horizontal portion positioned below and aligned with the horizontal portion of the injection well, the cyclic in situ combustion method comprising:
(i) operating at least one well as an oxidizing gas injection well;
(ii) injecting oxidizing gas through the oxidizing gas injection well into a corresponding one of the mobilized chambers to form a combustion region at least partially sustained by residual hydrocarbons in the reservoir, the combustion region having a combustion front;
(iii) promoting displacement of the combustion front through the interwell communication zone to sweep the array of well pairs;
(iv) pressurizing the interwell communication zone;
(v) producing a blowdown portion of the heavy hydrocarbons therefrom; and (vi) cyclically repeating steps (i) to (v).
30. The process of claim 29, wherein step (i) comprises converting a fluid injection well of one of the well pairs into the oxidizing gas injection well.
31. The process of claim 30, comprising operating the production well of the well pair comprising the oxidizing gas injection well in shut-in or choked mode while injecting the oxidizing gas through the oxidizing gas injection well.
32. The process of claim 31, wherein the production well of the well pair comprising the oxidizing gas injection well is operated in shut-in mode as long as the oxidizing gas is injected through the oxidizing gas injection well.
33. The process of any one of claims 29 to 32, wherein step (iii) comprises:
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
operating the well pairs downstream of the combustion front in production mode while the combustion front advances there-toward;
and restricting each of the well pairs once the combustion front respectively reaches each of the well pairs.
34 34. The process of claim 33, wherein both the injection well and the production well of each well pair are operated in production mode while the combustion front advances there-toward.
35. The process of claim 33 or 34, wherein both the injection well and the production well of each well pair are operated in shut-in or choked mode once the combustion front respectively reaches each of the well pairs.
36. The process of any one of claims 33 to 35, wherein the restricting of each of the well pairs is preformed upon breakthrough of heat there-through.
37. The process of any one of claims 33 to 36, wherein the restricting of each of the well pairs is preformed upon breakthrough of combustion gas there-through.
38. The process of any one of claims 29 to 37, wherein step (iv) comprises operating the well pairs in shut-in or choke mode to achieve pressurization of the interwell communication zone.
39. The process of any one of claims 29 to 38, wherein step (v) comprises operating at least one of the wells of the array of well pairs in production mode.
40. The process of any one of claims 29 to 39, wherein step (v) comprises operating the production wells in production mode.
41. The process of any one of claims 29 to 40, wherein step (v) comprises operating the fluid injection well and the production well of each of the well pairs of the array in production mode.
42. The process of any one of claims 29 to 41, wherein the interwell communication zone extends along substantially the entire length of the horizontal portions of each of the well pairs.
43. The process of any one of claims 29 to 42, comprising providing at least one infill well positioned in between two adjacent well pairs.
44. The process of claim 43, comprising establishing fluid communication between the mobilized chambers and the at least one infill well thereby fluidly connecting the infill well with the interwell communication zone.
45. The process of claim 43 or 44, comprising converting the infill well into the oxidizing gas injection well.
46. The process of any one of claims 15 to 17, wherein step (iii) comprises:
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward; and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
operating the at least one infill well downstream of the combustion front in production mode while the combustion front advances there-toward; and restricting each of the at least one infill well once the combustion front respectively reaches each of the at least one infill well.
47. The process of claim 46, wherein each of the at least one infill well is operated in shut-in or choked mode once the combustion front respectively reaches each of the at least one infill well.
48. The process of any one of claims 43 to 47, wherein step (iv) comprises operating each of the at least one infill well in shut-in or choke mode to help achieve pressurization of the interwell communication zone.
49. The process of any one of claims 43 to 48, wherein step (v) comprises operating each of the at least one infill well in production mode.
50. The process of any one of claims 29 to 49, wherein step (vi) comprises selecting the same well as the oxidizing gas injection well for each cycle.
51. The process of any one of claims 29 to 49, wherein step (vi) comprises selecting a different well as the oxidizing gas injection well for a subsequent cycle.
52. The process of any one of claims 29 to 51, wherein a single well is used as the oxidizing gas injection well.
53. The process of any one of claims 29 to 52, wherein the oxidizing gas injection well is on one end of the interwell communication zone.
54. The process of claim 53, wherein the oxidizing gas injection well is the injection well of an outside one of the well pairs.
55. The process of claim 53 or 54, wherein the combustion front displaces from one end of the interwell communication zone over the array of well pairs to the opposed end of the interwell communication zone.
56. The process of claim 55, wherein the combustion front displaces across the array of well pairs in a direction perpendicular with respect to the well pairs.
57. The process of claim 43, wherein step (v) is performed so as to establish fluid communication between the interwell communication zone and the at least one infill well.
58. The process of any one of claims 1 to 57, wherein the interwell communication zone has a bitumen saturation of from about 0.20 to less than about 0.05.
59. The process of any one of claims 1 to 58, wherein the oxidizing gas injection well injects air at an injection flux of about 0.3 to about 1.2 m3(ST)/m2.hour.
60. The process of any one of claims 1 to 59, wherein the interwell communication zone has a porosity between about 0.30 to 0.35.
61. The process of any one of claims 1 to 60, wherein the interwell communication zone has a temperature of at least about 150 C upon initial injection of the oxidizing gas.
62. The process of any one of claims 1 to 61, wherein the interwell communication zone has a temperature of at least about 175 C upon initial injection of the oxidizing gas.
63. The process of any one of claims 1 to 62, wherein the interwell communication zone has a temperature of at least about 200 C upon initial injection of the oxidizing gas.
64. The process of any one of claims 1 to 63, wherein the oxidizing gas is oxygen, air, enriched air, a mixture steam/air or a mixture thereof.
65. The process of any one of claims 1 to 64, wherein the oxidizing gas further comprises additional components including methane or fuel gas or a combination thereof.
66. The process of any one of claims 1 to 65, wherein the oxidizing gas further comprises CO2, recovered flue gases from a previous combustion cycle, and/or N2.
67. The process of any one of claims 1 to 66, wherein the oxidizing gas further comprises water.
68. The process of any one of claims 1 to 64, wherein the oxidizing gas is oxygen or air or a combination thereof.
69. The process of any one of claims 1 to 64, wherein the oxidizing gas is air.
Priority Applications (5)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2971941A CA2971941C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA2847742A CA2847742C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature steam-assisted gravity drainage operations |
| CA3027547A CA3027547C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA3168169A CA3168169A1 (en) | 2011-06-28 | 2011-06-28 | Process for recovering hydrocarbons including an in situ combustion phase |
| CA2744640A CA2744640C (en) | 2011-06-28 | 2011-06-28 | Cyclic combustion recovery process for mature in situ operations |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2744640A CA2744640C (en) | 2011-06-28 | 2011-06-28 | Cyclic combustion recovery process for mature in situ operations |
Related Child Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2847742A Division CA2847742C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature steam-assisted gravity drainage operations |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2744640A1 true CA2744640A1 (en) | 2012-12-28 |
| CA2744640C CA2744640C (en) | 2014-11-18 |
Family
ID=47392174
Family Applications (5)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA3027547A Active CA3027547C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA2847742A Active CA2847742C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature steam-assisted gravity drainage operations |
| CA2971941A Active CA2971941C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA3168169A Pending CA3168169A1 (en) | 2011-06-28 | 2011-06-28 | Process for recovering hydrocarbons including an in situ combustion phase |
| CA2744640A Active CA2744640C (en) | 2011-06-28 | 2011-06-28 | Cyclic combustion recovery process for mature in situ operations |
Family Applications Before (4)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA3027547A Active CA3027547C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA2847742A Active CA2847742C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature steam-assisted gravity drainage operations |
| CA2971941A Active CA2971941C (en) | 2011-06-28 | 2011-06-28 | In situ combustion recovery process for mature hydrocarbon recovery operations |
| CA3168169A Pending CA3168169A1 (en) | 2011-06-28 | 2011-06-28 | Process for recovering hydrocarbons including an in situ combustion phase |
Country Status (1)
| Country | Link |
|---|---|
| CA (5) | CA3027547C (en) |
Families Citing this family (6)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN104011331B (en) | 2011-10-21 | 2017-09-01 | 尼克森能源无限责任公司 | With the SAGD method of oxygenation |
| CA2815737C (en) | 2012-05-15 | 2020-05-05 | Nexen Inc. | Steam assisted gravity drainage with added oxygen geometry for impaired bitumen reservoirs |
| CA2972203C (en) | 2017-06-29 | 2018-07-17 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| CA2974712C (en) | 2017-07-27 | 2018-09-25 | Imperial Oil Resources Limited | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| CA2978157C (en) | 2017-08-31 | 2018-10-16 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| CA2983541C (en) | 2017-10-24 | 2019-01-22 | Exxonmobil Upstream Research Company | Systems and methods for dynamic liquid level monitoring and control |
-
2011
- 2011-06-28 CA CA3027547A patent/CA3027547C/en active Active
- 2011-06-28 CA CA2847742A patent/CA2847742C/en active Active
- 2011-06-28 CA CA2971941A patent/CA2971941C/en active Active
- 2011-06-28 CA CA3168169A patent/CA3168169A1/en active Pending
- 2011-06-28 CA CA2744640A patent/CA2744640C/en active Active
Also Published As
| Publication number | Publication date |
|---|---|
| CA2847742C (en) | 2017-10-24 |
| CA2847742A1 (en) | 2012-12-28 |
| CA2744640C (en) | 2014-11-18 |
| CA2971941A1 (en) | 2012-12-28 |
| CA3168169A1 (en) | 2012-12-28 |
| CA3027547A1 (en) | 2012-12-28 |
| CA3027547C (en) | 2022-09-27 |
| CA2971941C (en) | 2019-02-05 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US20210277757A1 (en) | Pressure assisted oil recovery | |
| US7516789B2 (en) | Hydrocarbon recovery facilitated by in situ combustion utilizing horizontal well pairs | |
| CN102947539B (en) | Conductive-convective backflow method for destructive distillation | |
| CA2744640C (en) | Cyclic combustion recovery process for mature in situ operations | |
| CA2698454C (en) | Improved in-situ combustion recovery process using single horizontal well to produce oil and combustion gases to surface | |
| CA2553297C (en) | In situ process to recover heavy oil and bitumen | |
| CA3087645A1 (en) | In situ hydrocarbon recovery from pay zones between low permeability layers in a stratified reservoir region | |
| CA2899805C (en) | Dewatering lean zones with ncg injection using production and injection wells | |
| Miller et al. | Proposed air injection recovery of cold-produced heavy oil reservoirs | |
| US11156072B2 (en) | Well configuration for coinjection | |
| MX2014006253A (en) | Horizontal well line-drive oil recovery process. | |
| Hallam et al. | Pressure-up blowdown combustion: A channeled reservoir recovery process | |
| Turta et al. | In-situ combustion in the oil reservoirs underlain by bottom water. Review of the field and laboratory tests | |
| US20230147327A1 (en) | Optimizing steam and solvent injection timing in oil production | |
| US11668176B2 (en) | Well configuration for coinjection | |
| Gadelle | In-situ combustion pilot basic design and laboratory experiments | |
| Turta et al. | Preliminary considerations on application of steamflooding in a toe-to-heel configuration | |
| EP2025862A1 (en) | Method for enhancing recovery of heavy crude oil by in-situ combustion in the presence of strong aquifers |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request |