CA2963439A1 - The method of thermal reservoir stimulation - Google Patents
The method of thermal reservoir stimulation Download PDFInfo
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- CA2963439A1 CA2963439A1 CA2963439A CA2963439A CA2963439A1 CA 2963439 A1 CA2963439 A1 CA 2963439A1 CA 2963439 A CA2963439 A CA 2963439A CA 2963439 A CA2963439 A CA 2963439A CA 2963439 A1 CA2963439 A1 CA 2963439A1
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- Prior art keywords
- reservoir
- well
- wells
- pressure
- production
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Classifications
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- 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
-
- 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
- E21B43/14—Obtaining from a multiple-zone well
Abstract
The invention relates to mining and extraction of oil and can be used for heat treatment of the productive formation of heavy oil, the recovery of the hydraulic communication of the reservoir with the well, to increase recovery of heavy oil and well production, as well as the resumption of operation of non-profitable oil wells, natural gas wells, in the fresh, mineral and thermal water wells. The invention comprising a sealed heater, filled with heat transfer agent and placed in the borehole. Heater heats bottom section of the well, which drilled horizontal or deviated. The heater is built in the form of the circulation heat exchanger. It circulates preheated on the surface heat transfer agent.
Description
THE METHOD OF THERMAL RESERVOIR STIMULATION
Field of the Invention The invention relates to mining and extraction of oil and can be used for heat treatment of the productive formation of heavy oil, the recovery of the hydraulic communication of the reservoir with the well, to increase recovery of heavy oil and well production, as well as the resumption of operation of non-profitable oil wells, natural gas wells, in the fresh, mineral and thermal water wells.
Prior Art Known "Method of development of heavy oil deposits" (patent RU N22379494, E21V
43/24, published 20.01.2010) using a pair of horizontal injection and production wells. Horizontal sections of these wells are drilled parallel one above the other in a vertical plane of the reservoir formation, equipped with a tubing, allowing simultaneous injection of heat transfer agent, heating producing formation with the creation of the steam chamber, producing fluid from the production well through the tubing and control technological parameters of the reservoir and the well.
The ends of the tubing positioned on opposite ends of the horizontal sections of the wells. Heating of the reservoir starts with steam injection into both wells, heating inter-well reservoir area, reducing the viscosity of heavy oil.
Steam chamber is created by pumping heat transfer agent, propagating to the top of the reservoir increasing the steam chamber size. Samples of production fluid is taken periodically, 2-3 times a week.
These samples are tested for salinity of water in production fluid. Influence of changes in sample water salinity on the uniformity of the steam chamber heating is also analyzed. And depending on salinity of water sample, simultaneous uniform heating of the steam chamber is carried out by controlling the pumping mode of heat transfer agent or production rate until a stable value of mineralization in water sample is achieved.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure (greater than 1 MPa), since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= narrow field of application, associated with the inability to increase productivity of fresh, mineral and thermal water reservoirs;
= complicated control of the steam assisted gravity drainage (SAGD), which requires stopping the production for the analysis of water mineralization;
= big unproductive expenses associated with heating of the heat transfer agent to high temperatures for injection, where it mixes with the formation products and then this mix extracted to the surface (up to 80% of the heat transfer agent in the production fluid).
These expenses do not decrease with increasing formation temperature. And then there is more money spending on the separation of heat transfer agent from the reservoir production;
= high-pressure required for injection of the heat transfer agent (20 - 40 MPa) into the reservoir, that may cause a breakthrough of the heat transfer agent into water formations and/or absorbing formations, which may lead to the inability to use this method or disturbance of the ecological situation in underground water sources;
= inability to carry out analysis of the parameters of the injection well without stopping injection;
= oil recovery factor does not exceed 40 % due to formation of zones with high, relatively to the initial, reservoir permeability, and mudding due to impact of high pressure reservoir sections that are not in areas of high reservoir permeability, which excludes their further extraction through wells;
= the need to build additional costly pairs of steam injection and production horizontal wells, since the use of horizontal wells longer than 200 - 250 m with diameter more than 140 mm does not affect the efficiency of warming of the formation due to zones with high reservoir permeability;
= high financial and material costs, the use of expensive equipment operating at high pressures, and the need to build at least one pair of horizontal injection and production wells.
= reduced efficiency due to the impossibility of inclusion in production unheated zones Known "The method of heat treatment of the bottom of the well" (patent RU
N22266401, E21V
43/24, published 20.12.2005), where part the electric heater filled with water, sealed and placed in the bottom of the well while upper part of the heater is filled with an inert gas at an initial pressure pi. Once in the hole, water is heated to operating temperature T2, the pressure pi is determined from the relationship:
T1 V ¨ V2 = P2 _____________________________________ wherep2- working pressure inside the heater housing, corresponding to the temperature T2, Pa;
- the initial water temperature, K;
V - volume of the heater housing, M3;
V2 - working volume of water at the pressure P2 and temperature T2, m3;
- volume of water at a pressure pi and temperature T1, m3.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure,. since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= narrow field of application associated with the inability to use this method in horizontal wells due to descent on the electric wireline;
= narrow field of applications related to the need of the close access to high-voltage power lines (transmission lines), as to generate 1 MW of heat at a voltage of 380 V
current of 3700 A is required (roughly equal to the simultaneous use of 180 welding machines);
= necessity to use special expensive equipment (cables, sensors, relays, controls, components and connections, etc.), designed for high power consumption by the heater;
= increasing the length of the heater's electrode reduces the temperature per meter, which makes the method ineffective in wells with a long section of the stimulation;
= high cost of electricity with relatively little coverage of the reservoir, which significantly increases the time (approximately 15- 20 times in comparison with SAGD) before the start of commercial production;
= inability to carry out analysis of the parameters of the well and production without stopping the heater, as for its effectiveness the packer needs be installed in a vertical section above the stimulated section of the reservoir;
= increased time before start of the production in massive formations with a thickness more than 50 m and the inability to work in heterogeneous layers, as it is difficult to heat top section of the formation at an early stage.
The closest in technical essence is "Method of thermal stimulation (RU N2 Patent 2471064, E21V 43/24, published 27.12.2012 Bulletin Number 36) comprising a sealed heater, filled with heat transfer agent and placed in the borehole. Heater heats bottom section of the well, which drilled horizontal or deviated. The heater is built in the form of the circulation heat exchanger. It circulates preheated on the surface heat transfer agent. Before placing the heat exchanger downhole, full survey of the physical parameters of the formation is performed, such as in-situ reservoir pressure and the pressure required to fracture the formation. Upon heating the formation, the reservoir pressure is maintained not lower then initial formation pressure and not higher than the fracture pressure by producing gas and fluids from lower level of the well.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure, since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= reduced efficiency due to the impossibility of inclusion in the production non-producing zones;
Summary of the Invention Technical tasks for the proposed invention are to reduce energy costs for wells with high reservoir pressure and expansion of functionality due to the possibility of use in deep wells (with depth of more than 700 m), and the inclusion of non-producing zones in production by heating and producing in cyclic mode at a reduced pressure in the near-wellbore area.
The task is solved with The Method of Thermal Reservoir Stimulation, including full survey of the physical parameters of the formation, in-situ reservoir pressure and the pressure required to fracture the formation, drilling deviated or horizontal well, placing into the wellbore a sealed heater, filled with heat transfer agent, preheated on surface. Well is heated by circulating heat transfer agent, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure and production is done at the same time.
What is new in the method is that at least two identical parallel wells are built at the distance, providing hydrodynamic connection between the wells after the formation of the steam chamber above them. And the production from nearby wells is done in cyclic mode, producing from one well or another, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure.
What is also new is that the distance from the bottom of the reservoir or water contact level to the well selected in proportion to the initial water saturation of the reservoir production.
Brief Description of the Drawings Fig. 1 shows a scheme for implementing a well with horizontal wellbore.
Fig. 2 shows a section A-A of Fig. 1.
Best Mode for Carrying Out the Invention Two identical parallel are drilled in reservoir 2 with the placement of the wellbore 3 as described above and shown on Fig. 1. Then well is completed and perforation 4 of the casing 5 is performed or well can be completed any other way allowing the flowing of the production.
Then sealed heater 6 is lowered in the wellbore 3 equipped with temperature sensors (not shown); the heater, for example, made in the form of a pipe 7 in pipe 8, which is filled with heat transfer agent and connected to the heat generator 9 (for example a heat exchanger or a heating boiler). As the heater 6 is sealed, then for all kinds of reservoirs with any kind of producing fluid, any high temperature heat transfer agent can be used, including synthetic oils (for example Therminol produced by Solutia Inc. - Heat transfer agent designed for use in a range of temperatures from - 115 C to 400 C in liquid and vapor phase, or other similar agent from other producers: BP, "Shell", etc.) The heater 6 is connected with the heat generator 9 at the wellhead. It heats the heat transfer agent and pump 10 pumps it through the heater's circulation loop; for example, the agent is pumped into the inner pipe 7 till the sealed end 11 of the outer pipe 8, and then returns to heat generator through the space between pipes 7 and 8. Using readings of pressure gauge 12 and the temperature sensors in the well, downhole wellbore pressure is controlled by producing fluid from reservoir 2 or pumping fluid or steam into the well, using pump 13.
At the start of the heating of the reservoir 2, the pressure in the wellbore 1 builds up by boiling and expansion of the wellbore fluid and the expansion of the gas at the bottom of the well (located at a depth H2 - Figures 2 or 3). Heated fluid or gas move up on the vertical section 14 (Fig 1, 2, or 3) and go into tank 15. Light fractions of collected in tank 15 fluids can be used for further operations.
As heating to 80 0C (when the viscosity of heavy oil drastically reduced) and coverage of the temperature stimulation of the reservoir 2 is increased, the volume of incoming product into the well 1 is increased and the power of the heater 6 is not sufficient for bring the liquid coming from the reservoir
Field of the Invention The invention relates to mining and extraction of oil and can be used for heat treatment of the productive formation of heavy oil, the recovery of the hydraulic communication of the reservoir with the well, to increase recovery of heavy oil and well production, as well as the resumption of operation of non-profitable oil wells, natural gas wells, in the fresh, mineral and thermal water wells.
Prior Art Known "Method of development of heavy oil deposits" (patent RU N22379494, E21V
43/24, published 20.01.2010) using a pair of horizontal injection and production wells. Horizontal sections of these wells are drilled parallel one above the other in a vertical plane of the reservoir formation, equipped with a tubing, allowing simultaneous injection of heat transfer agent, heating producing formation with the creation of the steam chamber, producing fluid from the production well through the tubing and control technological parameters of the reservoir and the well.
The ends of the tubing positioned on opposite ends of the horizontal sections of the wells. Heating of the reservoir starts with steam injection into both wells, heating inter-well reservoir area, reducing the viscosity of heavy oil.
Steam chamber is created by pumping heat transfer agent, propagating to the top of the reservoir increasing the steam chamber size. Samples of production fluid is taken periodically, 2-3 times a week.
These samples are tested for salinity of water in production fluid. Influence of changes in sample water salinity on the uniformity of the steam chamber heating is also analyzed. And depending on salinity of water sample, simultaneous uniform heating of the steam chamber is carried out by controlling the pumping mode of heat transfer agent or production rate until a stable value of mineralization in water sample is achieved.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure (greater than 1 MPa), since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= narrow field of application, associated with the inability to increase productivity of fresh, mineral and thermal water reservoirs;
= complicated control of the steam assisted gravity drainage (SAGD), which requires stopping the production for the analysis of water mineralization;
= big unproductive expenses associated with heating of the heat transfer agent to high temperatures for injection, where it mixes with the formation products and then this mix extracted to the surface (up to 80% of the heat transfer agent in the production fluid).
These expenses do not decrease with increasing formation temperature. And then there is more money spending on the separation of heat transfer agent from the reservoir production;
= high-pressure required for injection of the heat transfer agent (20 - 40 MPa) into the reservoir, that may cause a breakthrough of the heat transfer agent into water formations and/or absorbing formations, which may lead to the inability to use this method or disturbance of the ecological situation in underground water sources;
= inability to carry out analysis of the parameters of the injection well without stopping injection;
= oil recovery factor does not exceed 40 % due to formation of zones with high, relatively to the initial, reservoir permeability, and mudding due to impact of high pressure reservoir sections that are not in areas of high reservoir permeability, which excludes their further extraction through wells;
= the need to build additional costly pairs of steam injection and production horizontal wells, since the use of horizontal wells longer than 200 - 250 m with diameter more than 140 mm does not affect the efficiency of warming of the formation due to zones with high reservoir permeability;
= high financial and material costs, the use of expensive equipment operating at high pressures, and the need to build at least one pair of horizontal injection and production wells.
= reduced efficiency due to the impossibility of inclusion in production unheated zones Known "The method of heat treatment of the bottom of the well" (patent RU
N22266401, E21V
43/24, published 20.12.2005), where part the electric heater filled with water, sealed and placed in the bottom of the well while upper part of the heater is filled with an inert gas at an initial pressure pi. Once in the hole, water is heated to operating temperature T2, the pressure pi is determined from the relationship:
T1 V ¨ V2 = P2 _____________________________________ wherep2- working pressure inside the heater housing, corresponding to the temperature T2, Pa;
- the initial water temperature, K;
V - volume of the heater housing, M3;
V2 - working volume of water at the pressure P2 and temperature T2, m3;
- volume of water at a pressure pi and temperature T1, m3.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure,. since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= narrow field of application associated with the inability to use this method in horizontal wells due to descent on the electric wireline;
= narrow field of applications related to the need of the close access to high-voltage power lines (transmission lines), as to generate 1 MW of heat at a voltage of 380 V
current of 3700 A is required (roughly equal to the simultaneous use of 180 welding machines);
= necessity to use special expensive equipment (cables, sensors, relays, controls, components and connections, etc.), designed for high power consumption by the heater;
= increasing the length of the heater's electrode reduces the temperature per meter, which makes the method ineffective in wells with a long section of the stimulation;
= high cost of electricity with relatively little coverage of the reservoir, which significantly increases the time (approximately 15- 20 times in comparison with SAGD) before the start of commercial production;
= inability to carry out analysis of the parameters of the well and production without stopping the heater, as for its effectiveness the packer needs be installed in a vertical section above the stimulated section of the reservoir;
= increased time before start of the production in massive formations with a thickness more than 50 m and the inability to work in heterogeneous layers, as it is difficult to heat top section of the formation at an early stage.
The closest in technical essence is "Method of thermal stimulation (RU N2 Patent 2471064, E21V 43/24, published 27.12.2012 Bulletin Number 36) comprising a sealed heater, filled with heat transfer agent and placed in the borehole. Heater heats bottom section of the well, which drilled horizontal or deviated. The heater is built in the form of the circulation heat exchanger. It circulates preheated on the surface heat transfer agent. Before placing the heat exchanger downhole, full survey of the physical parameters of the formation is performed, such as in-situ reservoir pressure and the pressure required to fracture the formation. Upon heating the formation, the reservoir pressure is maintained not lower then initial formation pressure and not higher than the fracture pressure by producing gas and fluids from lower level of the well.
The disadvantages of this method are:
= high energy consumption in wells with high formation pressure, since a higher temperature required for the transition of the water into steam;
= low efficiency, including the wells with the depth of 700 - 800 m, due to impossibility of transition of water into the steam;
= reduced efficiency due to the impossibility of inclusion in the production non-producing zones;
Summary of the Invention Technical tasks for the proposed invention are to reduce energy costs for wells with high reservoir pressure and expansion of functionality due to the possibility of use in deep wells (with depth of more than 700 m), and the inclusion of non-producing zones in production by heating and producing in cyclic mode at a reduced pressure in the near-wellbore area.
The task is solved with The Method of Thermal Reservoir Stimulation, including full survey of the physical parameters of the formation, in-situ reservoir pressure and the pressure required to fracture the formation, drilling deviated or horizontal well, placing into the wellbore a sealed heater, filled with heat transfer agent, preheated on surface. Well is heated by circulating heat transfer agent, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure and production is done at the same time.
What is new in the method is that at least two identical parallel wells are built at the distance, providing hydrodynamic connection between the wells after the formation of the steam chamber above them. And the production from nearby wells is done in cyclic mode, producing from one well or another, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure.
What is also new is that the distance from the bottom of the reservoir or water contact level to the well selected in proportion to the initial water saturation of the reservoir production.
Brief Description of the Drawings Fig. 1 shows a scheme for implementing a well with horizontal wellbore.
Fig. 2 shows a section A-A of Fig. 1.
Best Mode for Carrying Out the Invention Two identical parallel are drilled in reservoir 2 with the placement of the wellbore 3 as described above and shown on Fig. 1. Then well is completed and perforation 4 of the casing 5 is performed or well can be completed any other way allowing the flowing of the production.
Then sealed heater 6 is lowered in the wellbore 3 equipped with temperature sensors (not shown); the heater, for example, made in the form of a pipe 7 in pipe 8, which is filled with heat transfer agent and connected to the heat generator 9 (for example a heat exchanger or a heating boiler). As the heater 6 is sealed, then for all kinds of reservoirs with any kind of producing fluid, any high temperature heat transfer agent can be used, including synthetic oils (for example Therminol produced by Solutia Inc. - Heat transfer agent designed for use in a range of temperatures from - 115 C to 400 C in liquid and vapor phase, or other similar agent from other producers: BP, "Shell", etc.) The heater 6 is connected with the heat generator 9 at the wellhead. It heats the heat transfer agent and pump 10 pumps it through the heater's circulation loop; for example, the agent is pumped into the inner pipe 7 till the sealed end 11 of the outer pipe 8, and then returns to heat generator through the space between pipes 7 and 8. Using readings of pressure gauge 12 and the temperature sensors in the well, downhole wellbore pressure is controlled by producing fluid from reservoir 2 or pumping fluid or steam into the well, using pump 13.
At the start of the heating of the reservoir 2, the pressure in the wellbore 1 builds up by boiling and expansion of the wellbore fluid and the expansion of the gas at the bottom of the well (located at a depth H2 - Figures 2 or 3). Heated fluid or gas move up on the vertical section 14 (Fig 1, 2, or 3) and go into tank 15. Light fractions of collected in tank 15 fluids can be used for further operations.
As heating to 80 0C (when the viscosity of heavy oil drastically reduced) and coverage of the temperature stimulation of the reservoir 2 is increased, the volume of incoming product into the well 1 is increased and the power of the heater 6 is not sufficient for bring the liquid coming from the reservoir
2 to boil. Then, production is performed by pump 16 (submersible, rod or any other type), lowered down on tubing 17 and using dual-completion wellhead 18 (shown contingently).
End of tubing 17 located at the depth H1 to provide the most effective production from reservoir 2, maintaining the wellbore pressure below formation pressure, but not less than fracture closure pressure in the reservoir (to avoid reduction of reservoir features). Such pressure in well 3 reduces the pressure of the heated portion of the formation 2 (in the near wellbore zone), at the same time reducing the boiling point of water and light fractions. This can significantly reduce the energy expended on heating to the boiling point of water. For example: for heavy oil reservoirs with a depth of the top of production zone 200 -250 m, length of the borehole 3 in the formation of 600 - 650 m, heater temperature - 300 C; the reduction in reservoir pressure from 1.4 to 1.0 MPa reduces the energy costs of heating by 32 ¨38 %
depending on the losses. Same thing for deep wells with the depth of the top of production zone more than 700 m, where most thermal technologies do not work at all, the pressure drop in the well 3, by producing from the well, allows the use of convection in the reservoir 2 for the production. Wellhead valves 20 are used to distribute the production, extracted from reservoir 2 and control the volume of injecting fluid or steam. The heater 6 is centralized in casing 5 (Fig. 4) using rigid or spring centralizers 21 (Fig. 4), tubing 7 is centralized inside the heater 6 using centralizers 22 as well. The distance L between neighboring wells 1 and 1' in reservoir 2 provides a hydrodynamic communication between them after the formation of the steam chamber above them (normally 15 to 150 m in direct proportion to the permeability of the reservoir 2). Production from the wells 1 and 1' cycled alternately, allowing pressure drop between these wells and the displacement of the reservoir fluid between them with heating in the direction of the producing well, which leads to involving non-productive zones into production As a result of the production from the well 1 or other neighbour production wells 1', pressure in the near wellbore zone decreases. To maintain formation pressure in the near wellbore zone fluid is pumped into the well 1 or 1' using pump 13. (any kind of fluid might be used;
for example: water, water mixed with solvents, including hydrocarbon solvents, oil, etc.), Gas cut fluid and / or dried steam also can be used. As a result, wellbore fluid is brought to a boil, gas, generated steam and / or injected steam are heated further, and create the pressure in well 1 or 1' (Fig. 2) necessary for the further development of the reservoir and this pressure is maintained above the initial formation pressure and below the fracture pressure to preserve the integrity of the reservoir 2. At the same time producing from well 1 or 1'. Light fractions of produced fluid also can be used as the hydrocarbon solvent. Water mixed with hydrocarbon solvents, oil and gas cut fluid are used for injection into the reservoir 2 for the most efficient displacement of high viscosity and high-tar oil with additional their liquefaction. In water reservoirs or oil reservoirs, where steam chamber at the top of the reservoir has already formed (not shown on figures), water and steam are used to maintain a balance between temperature, pressure and volume of the chamber, keeping water in the vapor state.
If the initial water saturation is over 10% distance LH from the bottom of the formation 23 or the level of the oil-water contact 23 to the borehole 3 is selected with respect to the thickness of the reservoir 1-1, (Figure 2) proportionally to the initial water saturation of the reservoir 2. This can be determined by the formula:
L,{
¨ ====-== Sws where LH - distance from the bottom of the formation 23 or the level of the oil-water contact 23 to the borehole 3 (Fig 1.), m;
Fir - thickness of the reservoir 2 (Fig. 2.), m;
Sws - initial water saturation.
This provides the maximum oil recovery factor from the reservoir 2, due to displacement of oil with the hot water setting at the bottom of the reservoir 2.
If the initial water saturation below 10%, wellbore 3 is placed as close to oil-water contact level as possible.
Production is carried out from well 1 or 1' in cyclic mode, one ta a time.
Production is continued until daily oil production is decreased by 50% or water cut of the produced fluid is increased above the initial water saturation, which ensures the maximum oil recovery between wells 1 and 1. Due to high temperature, light oil fractions are in a vapor state and at early stage mostly heavy fractions of oil are produced from well 1 or 1', thereby reducing the viscosity of the reservoir fluid. During the heating wells 1 or 1' and producing from these wells due to the differential pressure between corresponding wells thermal front moves progressively towards the well 1 or 1 involved in the selection, heating the reservoir between these wells also reducing the viscosity of the reservoir fluid. Cumulative effect of reducing the viscosity of the reservoir fluid maximizes oil recovery between wells 1 and 1'.
When the water cut in one of the wells 1 or 1 ' reaches more than 90%, this well is converted into injection well, pumping heated coolant into the well (water, water mixed with solvents, including hydrocarbon solvents, oil, etc.) for higher oil recovery from the reservoir in the direction of production well.
The proposed method of thermal stimulation can reduce energy costs especially in wells with high formation pressure (more than 1 MPa) and extend the functionality due to the possibility of use in deep wells (with depth of more than 700 m) and inclusion of non-producing zones into production by heating and producing using cyclic mode under reduced pressure in the near-wellbore region.
The embodiments of the present invention for which an exclusive property or privilege is claimed are defined as follows:
1. At least two identical parallel wells are built at the distance, providing hydrodynamic connection between the wells after the formation of the steam chamber above them. And the production from nearby wells is done in cyclic mode, producing from one well or another, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure.
2. The distance from the bottom of the reservoir or water contact level to the well selected in proportion to the initial water saturation of the reservoir production.
End of tubing 17 located at the depth H1 to provide the most effective production from reservoir 2, maintaining the wellbore pressure below formation pressure, but not less than fracture closure pressure in the reservoir (to avoid reduction of reservoir features). Such pressure in well 3 reduces the pressure of the heated portion of the formation 2 (in the near wellbore zone), at the same time reducing the boiling point of water and light fractions. This can significantly reduce the energy expended on heating to the boiling point of water. For example: for heavy oil reservoirs with a depth of the top of production zone 200 -250 m, length of the borehole 3 in the formation of 600 - 650 m, heater temperature - 300 C; the reduction in reservoir pressure from 1.4 to 1.0 MPa reduces the energy costs of heating by 32 ¨38 %
depending on the losses. Same thing for deep wells with the depth of the top of production zone more than 700 m, where most thermal technologies do not work at all, the pressure drop in the well 3, by producing from the well, allows the use of convection in the reservoir 2 for the production. Wellhead valves 20 are used to distribute the production, extracted from reservoir 2 and control the volume of injecting fluid or steam. The heater 6 is centralized in casing 5 (Fig. 4) using rigid or spring centralizers 21 (Fig. 4), tubing 7 is centralized inside the heater 6 using centralizers 22 as well. The distance L between neighboring wells 1 and 1' in reservoir 2 provides a hydrodynamic communication between them after the formation of the steam chamber above them (normally 15 to 150 m in direct proportion to the permeability of the reservoir 2). Production from the wells 1 and 1' cycled alternately, allowing pressure drop between these wells and the displacement of the reservoir fluid between them with heating in the direction of the producing well, which leads to involving non-productive zones into production As a result of the production from the well 1 or other neighbour production wells 1', pressure in the near wellbore zone decreases. To maintain formation pressure in the near wellbore zone fluid is pumped into the well 1 or 1' using pump 13. (any kind of fluid might be used;
for example: water, water mixed with solvents, including hydrocarbon solvents, oil, etc.), Gas cut fluid and / or dried steam also can be used. As a result, wellbore fluid is brought to a boil, gas, generated steam and / or injected steam are heated further, and create the pressure in well 1 or 1' (Fig. 2) necessary for the further development of the reservoir and this pressure is maintained above the initial formation pressure and below the fracture pressure to preserve the integrity of the reservoir 2. At the same time producing from well 1 or 1'. Light fractions of produced fluid also can be used as the hydrocarbon solvent. Water mixed with hydrocarbon solvents, oil and gas cut fluid are used for injection into the reservoir 2 for the most efficient displacement of high viscosity and high-tar oil with additional their liquefaction. In water reservoirs or oil reservoirs, where steam chamber at the top of the reservoir has already formed (not shown on figures), water and steam are used to maintain a balance between temperature, pressure and volume of the chamber, keeping water in the vapor state.
If the initial water saturation is over 10% distance LH from the bottom of the formation 23 or the level of the oil-water contact 23 to the borehole 3 is selected with respect to the thickness of the reservoir 1-1, (Figure 2) proportionally to the initial water saturation of the reservoir 2. This can be determined by the formula:
L,{
¨ ====-== Sws where LH - distance from the bottom of the formation 23 or the level of the oil-water contact 23 to the borehole 3 (Fig 1.), m;
Fir - thickness of the reservoir 2 (Fig. 2.), m;
Sws - initial water saturation.
This provides the maximum oil recovery factor from the reservoir 2, due to displacement of oil with the hot water setting at the bottom of the reservoir 2.
If the initial water saturation below 10%, wellbore 3 is placed as close to oil-water contact level as possible.
Production is carried out from well 1 or 1' in cyclic mode, one ta a time.
Production is continued until daily oil production is decreased by 50% or water cut of the produced fluid is increased above the initial water saturation, which ensures the maximum oil recovery between wells 1 and 1. Due to high temperature, light oil fractions are in a vapor state and at early stage mostly heavy fractions of oil are produced from well 1 or 1', thereby reducing the viscosity of the reservoir fluid. During the heating wells 1 or 1' and producing from these wells due to the differential pressure between corresponding wells thermal front moves progressively towards the well 1 or 1 involved in the selection, heating the reservoir between these wells also reducing the viscosity of the reservoir fluid. Cumulative effect of reducing the viscosity of the reservoir fluid maximizes oil recovery between wells 1 and 1'.
When the water cut in one of the wells 1 or 1 ' reaches more than 90%, this well is converted into injection well, pumping heated coolant into the well (water, water mixed with solvents, including hydrocarbon solvents, oil, etc.) for higher oil recovery from the reservoir in the direction of production well.
The proposed method of thermal stimulation can reduce energy costs especially in wells with high formation pressure (more than 1 MPa) and extend the functionality due to the possibility of use in deep wells (with depth of more than 700 m) and inclusion of non-producing zones into production by heating and producing using cyclic mode under reduced pressure in the near-wellbore region.
The embodiments of the present invention for which an exclusive property or privilege is claimed are defined as follows:
1. At least two identical parallel wells are built at the distance, providing hydrodynamic connection between the wells after the formation of the steam chamber above them. And the production from nearby wells is done in cyclic mode, producing from one well or another, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure.
2. The distance from the bottom of the reservoir or water contact level to the well selected in proportion to the initial water saturation of the reservoir production.
Claims (2)
1. At least two identical parallel wells are built at the distance, providing hydrodynamic connection between the wells after the formation of the steam chamber above them. And the production from nearby wells is done in cyclic mode, producing from one well or another, keeping the reservoir pressure above the initial formation pressure and below the fracture pressure.
2. The distance from the bottom of the reservoir or water contact level to the well selected in proportion to the initial water saturation of the reservoir production.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2963439A CA2963439A1 (en) | 2017-04-06 | 2017-04-06 | The method of thermal reservoir stimulation |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2963439A CA2963439A1 (en) | 2017-04-06 | 2017-04-06 | The method of thermal reservoir stimulation |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2963439A1 true CA2963439A1 (en) | 2018-10-06 |
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2963439A Abandoned CA2963439A1 (en) | 2017-04-06 | 2017-04-06 | The method of thermal reservoir stimulation |
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| CA (1) | CA2963439A1 (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN109948182A (en) * | 2019-01-30 | 2019-06-28 | 西安交通大学 | A kind of calculation method for mid-deep strata geothermal well well spacing |
| RU2779502C1 (en) * | 2022-03-01 | 2022-09-08 | Федеральное государственное бюджетное образовательное учреждение высшего образования "Уфимский государственный нефтяной технический университет" | Method for borehole production of high-viscosity oil from an oil deposit with a gas cap |
-
2017
- 2017-04-06 CA CA2963439A patent/CA2963439A1/en not_active Abandoned
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN109948182A (en) * | 2019-01-30 | 2019-06-28 | 西安交通大学 | A kind of calculation method for mid-deep strata geothermal well well spacing |
| RU2779502C1 (en) * | 2022-03-01 | 2022-09-08 | Федеральное государственное бюджетное образовательное учреждение высшего образования "Уфимский государственный нефтяной технический университет" | Method for borehole production of high-viscosity oil from an oil deposit with a gas cap |
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