CA2841520A1 - System and method for recovery of bitumen from fractured carbonate reservoirs - Google Patents
System and method for recovery of bitumen from fractured carbonate reservoirs Download PDFInfo
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Abstract
A system and method for recovering hydrocarbons (e.g. heavy oil, bitumen) from subterranean fractured carbonate formations is provided, the system and method consisting of a combination of a first cycling injection and production phase from a first downhole well, and a second subsequent continuous injection phase from a second downhole well, while continuing production from the first well.
Description
SYSTEM AND METHOD FOR RECOVERY OF BITUMEN FROM
FRACTURED CARBONATE RESERVOIRS
Inventors: Daniel Yang, Moslem Hosseininejad, Stephen Brand, Neil Edmunds, Darcy Riva, Wei Wei Owner: LARICINA ENERGY LTD.
TECHNICAL FIELD
The present disclosure is generally related to a system and method for recovering hydrocarbons (e.g. heavy oil, bitumen) from subterranean fractured carbonate reservoirs.
More specifically, the present disclosure relates to a system and method consisting of a combination of cycling injection and production from the same downhole well within a reservoir to recover bitumen, and subsequent continuous injection via a second adjacent well while producing bitumen from the first well.
BACKGROUND
It is well known that reserves of non-renewable resources continue to decline and that those remaining, such as bitumen contained in carbonate formations, are difficult to recover. As a result, significant research and development into improved methods of bitumen recovery are being conducted.
In Alberta, Canada, an estimated 80 billion cubic meters of bitumen are contained in carbonate reservoirs. One such reservoir, the Upper Devonian Grosmont Formation of northeastern Alberta, is a dolomite carbonate reservoir with heterogeneous porosity and permeability estimated to contain over 64 billion cubic meters of oil. The bitumen contained in the Grosmont Formation is not producible by conventional methods due to the high viscosity of the bitumen, and the complex nature of the formation geology. Carbonate reservoirs, however, have fractures and vugs that can form an extensive network of pathways for gravity drainage of the bitumen.
In oil sands reservoirs, bitumen has been traditionally recovered by surface mining or in situ recovery processes. In situ recovery processes increase bitumen mobility through heat or dilution, and most commonly use steam (e.g. steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and steam flooding).
Other in
FRACTURED CARBONATE RESERVOIRS
Inventors: Daniel Yang, Moslem Hosseininejad, Stephen Brand, Neil Edmunds, Darcy Riva, Wei Wei Owner: LARICINA ENERGY LTD.
TECHNICAL FIELD
The present disclosure is generally related to a system and method for recovering hydrocarbons (e.g. heavy oil, bitumen) from subterranean fractured carbonate reservoirs.
More specifically, the present disclosure relates to a system and method consisting of a combination of cycling injection and production from the same downhole well within a reservoir to recover bitumen, and subsequent continuous injection via a second adjacent well while producing bitumen from the first well.
BACKGROUND
It is well known that reserves of non-renewable resources continue to decline and that those remaining, such as bitumen contained in carbonate formations, are difficult to recover. As a result, significant research and development into improved methods of bitumen recovery are being conducted.
In Alberta, Canada, an estimated 80 billion cubic meters of bitumen are contained in carbonate reservoirs. One such reservoir, the Upper Devonian Grosmont Formation of northeastern Alberta, is a dolomite carbonate reservoir with heterogeneous porosity and permeability estimated to contain over 64 billion cubic meters of oil. The bitumen contained in the Grosmont Formation is not producible by conventional methods due to the high viscosity of the bitumen, and the complex nature of the formation geology. Carbonate reservoirs, however, have fractures and vugs that can form an extensive network of pathways for gravity drainage of the bitumen.
In oil sands reservoirs, bitumen has been traditionally recovered by surface mining or in situ recovery processes. In situ recovery processes increase bitumen mobility through heat or dilution, and most commonly use steam (e.g. steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and steam flooding).
Other in
2 situ processes use a combination of steam and solvent (e.g. Expanding Solvent SAGD
(ES-SAGD), Liquid Addition to Steam to Enhance Recovery (LASER)). Research on pure solvent processes (e.g. Vapor Extraction Process (VAPEX) and N-Solv) is being conducted. Forms of electrical heating are also under development (e.g.
Electro-Thermal Dynamic Stripping Process (ET-DSP)) and some include solvent (e.g. Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH)).
The use of SAGD and CSS has been in the Grosmont Formation since the 1970s.
These attempts were unsuccessful and the industry instead focused on the commercialization of SAGD in unconsolidated sandstone where the geology tended to be more consistent than that of the fractured carbonate reservoirs. For example, one attribute of traditional SAGD, is the requirement that the injection wells be approximately 5 ¨ 7m directly above the production wells. It is well known that in sandstone applications, the vertical proximity of the injection and production wells is required to effectively establish thermal communication between the wells. SAGD wells are operated with a liquid saturated layer above the producer by controlling the temperature of the producer in what is referred to as steam trap controlled production. However, the vertical spacing between injection and production wells used in SAGD is likely inoperable in fractured carbonate reservoirs where steam from the injection well readily passes through fractures directly to the production well making it impossible to maintain the sub-cool temperature required for oil production.
Cyclic steam stimulation (or "huff and puff') process requires the injection of steam, a period of soak time and followed by production. CSS inherently has a lower recovery factor than SAGD because efficiency of the process declines with each cycle, which makes it uneconomical to operate much beyond 20% recovery of the original oil in place. In fractured carbonate reservoir, CSS is not feasible because the fracture network prevents pressure build up thus inhibiting the soak period. Hence, a recovery mechanism that depends on geo-mechanical effects is not achievable in fractured carbonate reservoirs.
A commercially viable system and method to recover bitumen from fractured carbonate formations is needed. Such a method may comprise a combination of cyclic
(ES-SAGD), Liquid Addition to Steam to Enhance Recovery (LASER)). Research on pure solvent processes (e.g. Vapor Extraction Process (VAPEX) and N-Solv) is being conducted. Forms of electrical heating are also under development (e.g.
Electro-Thermal Dynamic Stripping Process (ET-DSP)) and some include solvent (e.g. Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH)).
The use of SAGD and CSS has been in the Grosmont Formation since the 1970s.
These attempts were unsuccessful and the industry instead focused on the commercialization of SAGD in unconsolidated sandstone where the geology tended to be more consistent than that of the fractured carbonate reservoirs. For example, one attribute of traditional SAGD, is the requirement that the injection wells be approximately 5 ¨ 7m directly above the production wells. It is well known that in sandstone applications, the vertical proximity of the injection and production wells is required to effectively establish thermal communication between the wells. SAGD wells are operated with a liquid saturated layer above the producer by controlling the temperature of the producer in what is referred to as steam trap controlled production. However, the vertical spacing between injection and production wells used in SAGD is likely inoperable in fractured carbonate reservoirs where steam from the injection well readily passes through fractures directly to the production well making it impossible to maintain the sub-cool temperature required for oil production.
Cyclic steam stimulation (or "huff and puff') process requires the injection of steam, a period of soak time and followed by production. CSS inherently has a lower recovery factor than SAGD because efficiency of the process declines with each cycle, which makes it uneconomical to operate much beyond 20% recovery of the original oil in place. In fractured carbonate reservoir, CSS is not feasible because the fracture network prevents pressure build up thus inhibiting the soak period. Hence, a recovery mechanism that depends on geo-mechanical effects is not achievable in fractured carbonate reservoirs.
A commercially viable system and method to recover bitumen from fractured carbonate formations is needed. Such a method may comprise a combination of cyclic
3 and continuous recovery methods, whereby the cyclic operation may be practical, effective and necessary in an early phase in order to condition the reservoir for a second phase of continuous production.
SUMMARY
A system and method for recovering bitumen from fractured carbonate reservoirs is provided, said reservoir having at least a first and at least a second downhole well vertically spaced from one another, the system and method consisting of the combination of:
a first cyclic phase involving the injection of a first well injectant through the at least one first well, ceasing injection of the first injectant and producing bitumen through the first well, and continuing this cycling phase until bitumen adjacent the at least one second well is mobilized, and a second continuous phase involving the injection of a second injectant through the at least one second well and continuing to produce bitumen from the at least one first well.
The first and second well may be positioned substantially vertical to one another, with the at least one first well being substantially below the at least one second well. In one embodiment, the at least one first well may be positioned at or near a lower zone of the reservoir, while the at least one second well may be positioned at or near an upper zone of the reservoir.
Cycling of the first phase may continue the mobilization of bitumen in the fractures of the reservoir expands to or near the at least one second well. It is desirable that the second continuous or substantially continuous phase of the present system and method may establish stable gravity drainage of bitumen from the reservoir matrix. To maintain a fluid a density difference between fractures and matrix.
First and second injectants may be heat-carrying fluids having a lower density relative to the bitumen in the reservoir. First and second injectants may be capable of transfering heat to the reservoir, thereby changing the properties of the carbonate rock formation and/or fluids therewithin, and may be, for example, steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof.
SUMMARY
A system and method for recovering bitumen from fractured carbonate reservoirs is provided, said reservoir having at least a first and at least a second downhole well vertically spaced from one another, the system and method consisting of the combination of:
a first cyclic phase involving the injection of a first well injectant through the at least one first well, ceasing injection of the first injectant and producing bitumen through the first well, and continuing this cycling phase until bitumen adjacent the at least one second well is mobilized, and a second continuous phase involving the injection of a second injectant through the at least one second well and continuing to produce bitumen from the at least one first well.
The first and second well may be positioned substantially vertical to one another, with the at least one first well being substantially below the at least one second well. In one embodiment, the at least one first well may be positioned at or near a lower zone of the reservoir, while the at least one second well may be positioned at or near an upper zone of the reservoir.
Cycling of the first phase may continue the mobilization of bitumen in the fractures of the reservoir expands to or near the at least one second well. It is desirable that the second continuous or substantially continuous phase of the present system and method may establish stable gravity drainage of bitumen from the reservoir matrix. To maintain a fluid a density difference between fractures and matrix.
First and second injectants may be heat-carrying fluids having a lower density relative to the bitumen in the reservoir. First and second injectants may be capable of transfering heat to the reservoir, thereby changing the properties of the carbonate rock formation and/or fluids therewithin, and may be, for example, steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof.
4 In one embodiment, a method for recovering bitumen from fractured carbonate reservoirs, said reservoir having at least a first and a second downhole well vertically spaced from one another is provided, the method comprising:
a) injecting a first injectant into the reservoir through the at least one first well, b) ceasing injection of the first injectant and producing bitumen through the at least one first well, c) cycling steps a and b, until the bitumen adjacent the at least one second well is mobilized, d) injecting a second injectant into the reservoir through the at least one second well, and e) continuing to produce bitumen via the at least one first well.
In another embodiment, a system for recovering bitumen from a fractured carbonate reservoir is provided, the system consisting of at least one first well for injecting first well injectant into the reservoir and producing bitumen from the reservoir, at least one second well, positioned substantially above the at least one first well, capable of injecting a second injectant into the reservoir, wherein the at least one first well and at least one second well are at least 25 meters apart from one another.
DESCRIPTION OF THE DRAWINGS
Figure 1 shows a schematic illustration of one embodiment of the present system and method in a fractured carbonate reservoir having steam (S), water (W), and mobile bitumen (B) in matrix (M), during an injection stage of the first cyclic phase (Fig. 1A), the production stage of the first cyclic phase (Fig. 1B), and the injection/production stage of the second phase (Fig. 1C); and Figure 2 shows a side view schematic of one embodiment of the present system and method showing a well pair positioned within the upper and lower zones of the same reservoir;
Figure 3 shows a side view schematic of one embodiment of the present system and method showing a well pair positioned in upper and lower zones of adjacent reservoirs;
Figure 4 shows a cross-sectional schematic of the well pair shown in Fig. 2;
Figure 5 shows a cross-sectional schematic showing a well pair being offset wherein first bottom wells 10 are in fluid communication with second top well 20;
Figure 6 shows a cross-sectional schematic of the well pairs showing in Fig.
3;
Figure 7 shows a cross-section schematic of a well pair being offset wherein first bottom
a) injecting a first injectant into the reservoir through the at least one first well, b) ceasing injection of the first injectant and producing bitumen through the at least one first well, c) cycling steps a and b, until the bitumen adjacent the at least one second well is mobilized, d) injecting a second injectant into the reservoir through the at least one second well, and e) continuing to produce bitumen via the at least one first well.
In another embodiment, a system for recovering bitumen from a fractured carbonate reservoir is provided, the system consisting of at least one first well for injecting first well injectant into the reservoir and producing bitumen from the reservoir, at least one second well, positioned substantially above the at least one first well, capable of injecting a second injectant into the reservoir, wherein the at least one first well and at least one second well are at least 25 meters apart from one another.
DESCRIPTION OF THE DRAWINGS
Figure 1 shows a schematic illustration of one embodiment of the present system and method in a fractured carbonate reservoir having steam (S), water (W), and mobile bitumen (B) in matrix (M), during an injection stage of the first cyclic phase (Fig. 1A), the production stage of the first cyclic phase (Fig. 1B), and the injection/production stage of the second phase (Fig. 1C); and Figure 2 shows a side view schematic of one embodiment of the present system and method showing a well pair positioned within the upper and lower zones of the same reservoir;
Figure 3 shows a side view schematic of one embodiment of the present system and method showing a well pair positioned in upper and lower zones of adjacent reservoirs;
Figure 4 shows a cross-sectional schematic of the well pair shown in Fig. 2;
Figure 5 shows a cross-sectional schematic showing a well pair being offset wherein first bottom wells 10 are in fluid communication with second top well 20;
Figure 6 shows a cross-sectional schematic of the well pairs showing in Fig.
3;
Figure 7 shows a cross-section schematic of a well pair being offset wherein first bottom
5 well 10 is in fluid communication with second top wells 20 positioned in an adjacent reservoir; and Figure 8 shows a cross-section schematic of a well configuration comprising at least one first well 10, at least one second well 20, and at least one third well 30;
Figure 9 shows a graph plotting the viscosity of bitumen relative to the temperature of the bitumen;
Figure 10 shows a schematic of gravity drainage through the reservoir towards at least one bottom production well 10; and Figure 11 shows the flow of bitumen B where flow barriers are encountered and bitumen B drains in and out of the M (A), and into the fracture network (B).
DESCRIPTION OF THE EMBODIMENTS
The present system and method relate to bitumen recovery from fractured carbonate reservoirs, said reservoir having at least two downhole wells that are vertically separated from one another, and preferably positioned substantially above and below one another. More specifically, the present system and method generally relate to the combination of two phases, namely, a first cyclic phase to achieve mobilization of bitumen in the reservoir, consisting of cycling the injection of a heat-carrying fluid into the reservoir and production of bitumen from at least one first downhole well until bitumen is mobilized between the first well and at least one second well adjacent thereto, and a second continuous phase consisting of the injection of a heat-carrying, lower density fluid via the second well while continuously producing bitumen from the first well. In one embodiment, the first well may be positioned substantially lower or below the second well, but any reference to the wells as top, bottom, upper or lower, are for description purposes only and are not intended to limit or narrow the scope of the present system and method.
Figure 9 shows a graph plotting the viscosity of bitumen relative to the temperature of the bitumen;
Figure 10 shows a schematic of gravity drainage through the reservoir towards at least one bottom production well 10; and Figure 11 shows the flow of bitumen B where flow barriers are encountered and bitumen B drains in and out of the M (A), and into the fracture network (B).
DESCRIPTION OF THE EMBODIMENTS
The present system and method relate to bitumen recovery from fractured carbonate reservoirs, said reservoir having at least two downhole wells that are vertically separated from one another, and preferably positioned substantially above and below one another. More specifically, the present system and method generally relate to the combination of two phases, namely, a first cyclic phase to achieve mobilization of bitumen in the reservoir, consisting of cycling the injection of a heat-carrying fluid into the reservoir and production of bitumen from at least one first downhole well until bitumen is mobilized between the first well and at least one second well adjacent thereto, and a second continuous phase consisting of the injection of a heat-carrying, lower density fluid via the second well while continuously producing bitumen from the first well. In one embodiment, the first well may be positioned substantially lower or below the second well, but any reference to the wells as top, bottom, upper or lower, are for description purposes only and are not intended to limit or narrow the scope of the present system and method.
6 Having regard to Fig. 1, in a first embodiment, the first cyclic phase of the present system and method may comprise the steps of:
a) injecting a first well injectant into the reservoir via at least one first well 10 (Fig. 1A), b) ceasing injection and producing bitumen through the same well 10 (Fig. 1B), and c) cycling steps a and b.
The first cyclic phase of the present system and method may be continued until the mobilization of bitumen in the fracture system expands towards at least one second well 20 adjacent to bottom well 10. The first cyclic phase of the present system and method may use both the bottom well 10 and the top well 20. The second continuous phase would comprise the same steps as the first embodiment.
The second continuous phase of the present system and method may comprise the steps of:
d) injecting a top well injectant into the reservoir via the top well 20, and e) producing bitumen via the bottom well 10 (Fig. 1C).
Second well injectant can be continuously injected via the top well 20, and the injection rate of said top well injectant can be modified or varied to, for example, maintain steam trap controlled production. The composition of the top well injectant and/or concentration of additives, if any, can be varied as would be known by a person skilled in the art.
Having regard to Figures 2 and 3, first and second wells 10, 20 can be positioned within the same reservoir, or reservoirs adjacent to, and in communication with, one another (e.g. adjacent reservoirs may be separated by a layer of marl, (L)).
For example, in the Upper Devonian Grosmont Formation of northeastern Alberta, first and second wells 10, 20 could both be positioned within Grosmont C (Fig. 2). However, if the Grosmont C and Grosmont D are separated by a layer (L), but still in communication, then well 10 could be placed in a lower zone, or Grosmont C, and well 20 could be placed in an upper zone, or Grosmont D, which together could be considered the reservoir (Fig. 3). It is understood that the location or depth (from the surface) of the
a) injecting a first well injectant into the reservoir via at least one first well 10 (Fig. 1A), b) ceasing injection and producing bitumen through the same well 10 (Fig. 1B), and c) cycling steps a and b.
The first cyclic phase of the present system and method may be continued until the mobilization of bitumen in the fracture system expands towards at least one second well 20 adjacent to bottom well 10. The first cyclic phase of the present system and method may use both the bottom well 10 and the top well 20. The second continuous phase would comprise the same steps as the first embodiment.
The second continuous phase of the present system and method may comprise the steps of:
d) injecting a top well injectant into the reservoir via the top well 20, and e) producing bitumen via the bottom well 10 (Fig. 1C).
Second well injectant can be continuously injected via the top well 20, and the injection rate of said top well injectant can be modified or varied to, for example, maintain steam trap controlled production. The composition of the top well injectant and/or concentration of additives, if any, can be varied as would be known by a person skilled in the art.
Having regard to Figures 2 and 3, first and second wells 10, 20 can be positioned within the same reservoir, or reservoirs adjacent to, and in communication with, one another (e.g. adjacent reservoirs may be separated by a layer of marl, (L)).
For example, in the Upper Devonian Grosmont Formation of northeastern Alberta, first and second wells 10, 20 could both be positioned within Grosmont C (Fig. 2). However, if the Grosmont C and Grosmont D are separated by a layer (L), but still in communication, then well 10 could be placed in a lower zone, or Grosmont C, and well 20 could be placed in an upper zone, or Grosmont D, which together could be considered the reservoir (Fig. 3). It is understood that the location or depth (from the surface) of the
7 well placement within the reservoir can vary, particularly depending upon the overall size and characteristics of the reservoir.
First bottom well 10 can be a horizontal or deviated well, and can be a combination of injection and production well. Injection of the bottom well injectant via first well 10 can occur until a desired temperature and pressure within the reservoir unit is reached that enables bitumen mobility, and then ceased to produce bitumen located in the reservoir unit through the same well 10. Second top well 20 can be a vertical, horizontal or deviated well, and can be a combination of injection and production well.
It is understood that the distance between first and second wells 10, 20 need not be limited and may depend upon the thickness and/or geological heterogeneity of the reservoir and the viscosity of the bitumen (e.g. the spacing could be greater where the bitumen has lower viscosity and/or the reservoir unit is thicker). In one embodiment, first and second wells 10, 20 may be spaced more than 25 meters apart (e.g.
vertically).
Preferably, the first and second wells 10, 20 are spaced between approximately 15 to 25 meters.
Having regard to Figs. 4 and 6, first well 10 can be positioned substantially above second well 20. Alternatively, first well 10 may be horizontally offset from second well (Figs. 5, and 7). When second well 20 is offset from first well 10, second well 20 provide support for two horizontally spaced first wells 10 (Fig. 5).
20 Having regard to Fig. 8, it is contemplated that second well 20 may provide heat to at least one third wells 30, positioned within the same reservoir or in a reservoir adjacent thereto, whereby third wells 30 are generally positioned above second wells 20.
This arrangement of wells allows for heat transfer and production to occur at third wells 30.
First and second well injectants can comprise an injectant that may be capable of changing the properties of the rock properties as well as the fluids therewithin. First bottom well injectant, injected via first well 10 during the first phase of the present system and method, may have a lower density fluid (relative to bitumen) that is capable of carrying heat and/or a diluent such as steam, steam and solvent, steam and non-condensable gas, non-condensable gas, solvent, or a combination thereof. A
surfactant or
First bottom well 10 can be a horizontal or deviated well, and can be a combination of injection and production well. Injection of the bottom well injectant via first well 10 can occur until a desired temperature and pressure within the reservoir unit is reached that enables bitumen mobility, and then ceased to produce bitumen located in the reservoir unit through the same well 10. Second top well 20 can be a vertical, horizontal or deviated well, and can be a combination of injection and production well.
It is understood that the distance between first and second wells 10, 20 need not be limited and may depend upon the thickness and/or geological heterogeneity of the reservoir and the viscosity of the bitumen (e.g. the spacing could be greater where the bitumen has lower viscosity and/or the reservoir unit is thicker). In one embodiment, first and second wells 10, 20 may be spaced more than 25 meters apart (e.g.
vertically).
Preferably, the first and second wells 10, 20 are spaced between approximately 15 to 25 meters.
Having regard to Figs. 4 and 6, first well 10 can be positioned substantially above second well 20. Alternatively, first well 10 may be horizontally offset from second well (Figs. 5, and 7). When second well 20 is offset from first well 10, second well 20 provide support for two horizontally spaced first wells 10 (Fig. 5).
20 Having regard to Fig. 8, it is contemplated that second well 20 may provide heat to at least one third wells 30, positioned within the same reservoir or in a reservoir adjacent thereto, whereby third wells 30 are generally positioned above second wells 20.
This arrangement of wells allows for heat transfer and production to occur at third wells 30.
First and second well injectants can comprise an injectant that may be capable of changing the properties of the rock properties as well as the fluids therewithin. First bottom well injectant, injected via first well 10 during the first phase of the present system and method, may have a lower density fluid (relative to bitumen) that is capable of carrying heat and/or a diluent such as steam, steam and solvent, steam and non-condensable gas, non-condensable gas, solvent, or a combination thereof. A
surfactant or
8 other chemical, such as an acid, may be added to the injectant such that the fluid properties (of the injectant or bitumen) or rock properties may be modified.
While no limitation in scope or interpretation of the present system and method is intended, it is contemplated that, in operation, the first bottom well injectant injected may travel preferentially through high permeability fractures in the reservoir, thereby conductively heating the reservoir and mobilizing the bitumen therein. For example, the bitumen may have a mobility of at least 50mD/cP. For example, Figs. 9 shows that at the initial reservoir of temperature approximately 10 C, the viscosity of the bitumen is approximately 10,000,000 cP and that raising the temperature of the bitumen to 80 C will reduce the viscosity to approximately 1,000 cP, increasing bitumen mobility by a factor of 10,000.
After successful mobility of the bitumen in the first cyclic phase of the present system and method, injection of second well injectant via the second top well 20 is commenced resulting in fluid with lower density than bitumen in the fracture network, thereby enabling stable gravity drainage through the reservoir and continuous production from the bottom well 10 (Fig. 10). In addition, the top well injectant will maintain and distribute heat in through the fracture network. It is contemplated that various effects such as solution gas drive effect, connate water vaporization, thermal expansion, and spontaneous imbibition, if wettability alteration occurs, will also contribute to the bitumen production.
Density differences between injectant in the fractures F and bitumen in the matrix M can result in gravity drainage, whereby the bitumen drains downwards in the matrix M
(due to gravity) until it encounters a flow barrier at which time it may diverge into a fracture. The flow barrier can be a geological feature, a lean zone or cold bitumen. When multiple flow barriers are encountered, the bitumen B may drain out of the matrix M at the first barrier and back into the matrix M below (replacing previously-drained bitumen), as depicted in Fig.11(A). Alternatively, the bitumen B may drain simultaneously into the fracture network, as depicted Fig. 11(B). Drainage rates of the bitumen B may further depend upon vertical matrix permeability and oil viscosity. The drainage rate is independent of the height of the drainage column, fracture spacing and/or
While no limitation in scope or interpretation of the present system and method is intended, it is contemplated that, in operation, the first bottom well injectant injected may travel preferentially through high permeability fractures in the reservoir, thereby conductively heating the reservoir and mobilizing the bitumen therein. For example, the bitumen may have a mobility of at least 50mD/cP. For example, Figs. 9 shows that at the initial reservoir of temperature approximately 10 C, the viscosity of the bitumen is approximately 10,000,000 cP and that raising the temperature of the bitumen to 80 C will reduce the viscosity to approximately 1,000 cP, increasing bitumen mobility by a factor of 10,000.
After successful mobility of the bitumen in the first cyclic phase of the present system and method, injection of second well injectant via the second top well 20 is commenced resulting in fluid with lower density than bitumen in the fracture network, thereby enabling stable gravity drainage through the reservoir and continuous production from the bottom well 10 (Fig. 10). In addition, the top well injectant will maintain and distribute heat in through the fracture network. It is contemplated that various effects such as solution gas drive effect, connate water vaporization, thermal expansion, and spontaneous imbibition, if wettability alteration occurs, will also contribute to the bitumen production.
Density differences between injectant in the fractures F and bitumen in the matrix M can result in gravity drainage, whereby the bitumen drains downwards in the matrix M
(due to gravity) until it encounters a flow barrier at which time it may diverge into a fracture. The flow barrier can be a geological feature, a lean zone or cold bitumen. When multiple flow barriers are encountered, the bitumen B may drain out of the matrix M at the first barrier and back into the matrix M below (replacing previously-drained bitumen), as depicted in Fig.11(A). Alternatively, the bitumen B may drain simultaneously into the fracture network, as depicted Fig. 11(B). Drainage rates of the bitumen B may further depend upon vertical matrix permeability and oil viscosity. The drainage rate is independent of the height of the drainage column, fracture spacing and/or
9 fracture permeability. Drainage rates may be impacted upon and sensitive to capillary pressure characteristics, which in turn may be a function of the interfacial tension between the bitumen and water.
Elevated reservoir temperatures may create a "solution gas drive" which is caused by light components in the bitumen (e.g. methane), which are initially dissolved as a liquid, to escape the bitumen and form a separate gas phase. The gas may accumulate in the pores of the matrix, and require room to expand, until all the bubbles connect and become mobile (i.e. it is understood that the gas would leave the pore if a driving force is present). In order to make space for the expanding gas, the bitumen trapped in the matrix is driven out of the matrix and into the fractures.
Further, a skilled person would know and understand that, because the pores of the matrix can contain connate water that will evaporate on heating, an internal steam drive from the matrix itself may synergistically drive bitumen from the matrix.
It is further understood that the desired reservoir temperature may be sufficient to result in the thermal expansion of the reservoir formation, thereby further increasing reservoir pressure and causing bitumen to be pushed out of the matrix and into the fractures, where it can easily move towards the well 10.
Fractured carbonate reservoirs are known to initially be oil-wet. A person skilled in the art would know that, at elevated temperature, wettability changes from oil-wet to water-wet resulting in a change in capillary pressure and spontaneous imbibition of water into the pores, forcing bitumen into the fracture network where it can easily move towards the well 10.
A person skilled in the art would know that a pressure gradient between the higher pressure at top well 20 and the pressure at bottom well 10 will drive (or "draw-down") the bitumen from the reservoir and towards the bottom well 10. Where fluids are continuously flowing to the lower-pressure bottom well 10, a fluid column will develop in the vicinity of the bottom well 10, and a positive "draw-down" pressure can be maintained.
In another embodiment, the second continuous phase of the present system and method may be optionally varied to cycle the pressure in the injectant filled fractures by, for example, maintaining steam trap controlled production while varying the injection rate or production rate. For instance, injection via top well 20 may only occur half of the time, but at double the rate that would be required to maintain an average cycle pressure, while continually producing from bottom well 10. A modified second continuous phase involving pressure cycling may be beneficial in a fractured carbonate formation by possibly generating bubbles of expanding gas and injectant that would drive bitumen from finer pores and into fractures. This process could further be utilized to maintain and control the cumulative injectant/oil ratio, and also steam allocations among wells in the reservoir.
Elevated reservoir temperatures may create a "solution gas drive" which is caused by light components in the bitumen (e.g. methane), which are initially dissolved as a liquid, to escape the bitumen and form a separate gas phase. The gas may accumulate in the pores of the matrix, and require room to expand, until all the bubbles connect and become mobile (i.e. it is understood that the gas would leave the pore if a driving force is present). In order to make space for the expanding gas, the bitumen trapped in the matrix is driven out of the matrix and into the fractures.
Further, a skilled person would know and understand that, because the pores of the matrix can contain connate water that will evaporate on heating, an internal steam drive from the matrix itself may synergistically drive bitumen from the matrix.
It is further understood that the desired reservoir temperature may be sufficient to result in the thermal expansion of the reservoir formation, thereby further increasing reservoir pressure and causing bitumen to be pushed out of the matrix and into the fractures, where it can easily move towards the well 10.
Fractured carbonate reservoirs are known to initially be oil-wet. A person skilled in the art would know that, at elevated temperature, wettability changes from oil-wet to water-wet resulting in a change in capillary pressure and spontaneous imbibition of water into the pores, forcing bitumen into the fracture network where it can easily move towards the well 10.
A person skilled in the art would know that a pressure gradient between the higher pressure at top well 20 and the pressure at bottom well 10 will drive (or "draw-down") the bitumen from the reservoir and towards the bottom well 10. Where fluids are continuously flowing to the lower-pressure bottom well 10, a fluid column will develop in the vicinity of the bottom well 10, and a positive "draw-down" pressure can be maintained.
In another embodiment, the second continuous phase of the present system and method may be optionally varied to cycle the pressure in the injectant filled fractures by, for example, maintaining steam trap controlled production while varying the injection rate or production rate. For instance, injection via top well 20 may only occur half of the time, but at double the rate that would be required to maintain an average cycle pressure, while continually producing from bottom well 10. A modified second continuous phase involving pressure cycling may be beneficial in a fractured carbonate formation by possibly generating bubbles of expanding gas and injectant that would drive bitumen from finer pores and into fractures. This process could further be utilized to maintain and control the cumulative injectant/oil ratio, and also steam allocations among wells in the reservoir.
10 The present system and method may be managed and optimized by varying the timing and length of the cycles of the first phase, the injection rate and volume and/or composition of both top and bottom injectants, the distance and spatial relationship between the top and bottom wells, and the timing of the transition between the first and second phases.
Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof, it being recognized that the invention is defined and limited only by the claims that follow.
Although a few embodiments have been shown and described, it will be appreciated by those skilled in the art that various changes and modifications can be made to these embodiments without changing or departing from their scope, intent or functionality. The terms and expressions used in the preceding specification have been used herein as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding equivalents of the features shown and described or portions thereof, it being recognized that the invention is defined and limited only by the claims that follow.
Claims (21)
1. A method for recovering bitumen from fractured carbonate reservoirs, said reservoir having at least a first and a second downhole well vertically spaced from one another, comprising:
a) injecting a first injectant into the reservoir through the at least one first well, b) ceasing injection of the first injectant and producing bitumen through the at least one first well, c) cycling steps a and b, until the bitumen adjacent the at least one second well is mobilized, d) injecting a second injectant into the reservoir through the at least one second well, and e) continuing to produce bitumen via the at least one first well.
a) injecting a first injectant into the reservoir through the at least one first well, b) ceasing injection of the first injectant and producing bitumen through the at least one first well, c) cycling steps a and b, until the bitumen adjacent the at least one second well is mobilized, d) injecting a second injectant into the reservoir through the at least one second well, and e) continuing to produce bitumen via the at least one first well.
2. The method of claim 1, wherein the first well is substantially below the second well.
3. The method of claims 1 or 2, wherein the cycling of steps a) and b) continues until the mobilization of bitumen in the reservoir fractures expands to or near the at least one second well.
4. The method of any one of claims 1 - 3, wherein the cycling of steps a) and b) continues until the mobilization of bitumen reaches at least 50 mD/cP.
5. The method of any one of the claim 1 - 4, wherein the first injectant comprises steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof.
6. The method of claim 5, wherein the first injectant may have a surfactant and/or an acid.
7. The method of any one of claims 1 - 6, wherein the second injectant comprises steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof.
8. The method of claim 7, wherein the second injectant may have a surfactant and/or an acid.
9. The method of any one of claims 1 ¨ 8, wherein the first and second injectant are injected substantially continuously.
10. The method of any one of claims 1 ¨ 9, wherein the injection rate of the first or second injectant is not continuous.
11. The method of any one of claims 1 - 10, wherein the at least one first well is positioned at or near a lower zone of the reservoir.
12. The method of any one of claims 1 - 11, wherein the at least one first well may be a horizontal or deviated well.
13. The method of any one of claims 1 - 12, wherein the second well is positioned at or near an upper zone of the reservoir.
14. The method of any one of claims 1 - 13, wherein the at least one second well may be a vertical, horizontal or deviated well.
15. The method of any one of claims 1 - 14, wherein the at least one first well may be positioned at least 25 meters from the at least one second well.
16. The method of any one of claims 1 ¨ 15, wherein the at least one first well is approximately 15¨ 25 meters from the at least one second well.
17. A system for recovering bitumen from a fractured carbonate reservoir, the system comprising:
a. at least one first well for injecting first well injectant into the reservoir and producing bitumen from the reservoir, b. at least one second well, positioned substantially above the at least one first well, capable of injecting a second injectant into the reservoir, wherein the at least one first well and at least one second well are at least 25 meters apart from one another.
a. at least one first well for injecting first well injectant into the reservoir and producing bitumen from the reservoir, b. at least one second well, positioned substantially above the at least one first well, capable of injecting a second injectant into the reservoir, wherein the at least one first well and at least one second well are at least 25 meters apart from one another.
18. The system of claim 17, wherein the first well injectant comprises steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof
19. The system of claim 18, wherein the first well injectant further has a surfactant and/or an acid.
20. The system of claim 17, wherein the second well injectant comprises steam, steam and solvent, steam and non-condensable gas, solvent, non-condensable gas, or a combination thereof.
21. The system of claim 20, wherein the second well injectant further has a surfactant and/or acid.
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| US201361869374P | 2013-08-23 | 2013-08-23 | |
| US61/869,374 | 2013-08-23 |
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Cited By (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10487636B2 (en) | 2017-07-27 | 2019-11-26 | Exxonmobil Upstream Research Company | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| US11002123B2 (en) | 2017-08-31 | 2021-05-11 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| US11142681B2 (en) | 2017-06-29 | 2021-10-12 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| US11261725B2 (en) | 2017-10-24 | 2022-03-01 | Exxonmobil Upstream Research Company | Systems and methods for estimating and controlling liquid level using periodic shut-ins |
-
2014
- 2014-01-31 CA CA2841520A patent/CA2841520C/en active Active
Cited By (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US11142681B2 (en) | 2017-06-29 | 2021-10-12 | Exxonmobil Upstream Research Company | Chasing solvent for enhanced recovery processes |
| US10487636B2 (en) | 2017-07-27 | 2019-11-26 | Exxonmobil Upstream Research Company | Enhanced methods for recovering viscous hydrocarbons from a subterranean formation as a follow-up to thermal recovery processes |
| US11002123B2 (en) | 2017-08-31 | 2021-05-11 | Exxonmobil Upstream Research Company | Thermal recovery methods for recovering viscous hydrocarbons from a subterranean formation |
| US11261725B2 (en) | 2017-10-24 | 2022-03-01 | Exxonmobil Upstream Research Company | Systems and methods for estimating and controlling liquid level using periodic shut-ins |
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| CA2841520C (en) | 2020-12-15 |
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