WASTE HEAT RECOVERY FROM DEPLETED RESERVOIR

FIELD

The present disclosure relates generally to methods of producing heat from a depleted reservoir.

BACKGROUND

A variety of processes are used to recover viscous hydrocarbons, such as heavy oils and bitumen, from reservoirs such as oil sands deposits. Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the Northern Alberta oil sands that are not susceptible to standard oil well production technologies. One problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir.

In some cases, such deposits are mined using open-pit mining techniques to extract hydrocarbon-bearing material for later processing to extract the hydrocarbons. Alternatively, thermal techniques may be used to heat the hydrocarbon reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.

One thermal method of recovering viscous hydrocarbons using two vertically spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and corresponding U.S. Pat. No. 4,344,485. In the SAGD process, steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while mobilized hydrocarbons are produced from a lower, parallel, horizontal, production well that is vertically spaced and near the injection well. The injection and production wells are located close to the bottom of the hydrocarbon deposit to collect the hydrocarbons that flow toward the bottom.

The SAGD process works as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term “steam chamber” is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands upwardly and laterally from the injection well, viscous hydrocarbons in the reservoir are heated and mobilized, in particular, at the margins of the steam chamber where the steam condenses and heats the viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons and aqueous condensate drain, under the effects of gravity, toward the bottom of the steam chamber, where the production well is located. The mobilized hydrocarbons are collected and produced from the production well. The rate of steam injection and the rate of hydrocarbon production may be modulated to control the growth of the steam chamber and ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons.

In situ Combustion (ISC) is another thermal method which may be utilized to recover hydrocarbons from underground hydrocarbon reservoirs. ISC includes the injection of an oxidizing gas into the porous rock of a hydrocarbon-containing reservoir to ignite and support combustion of the hydrocarbons around the wellbore. ISC may be initiated using an artificial igniter such as a downhole heater or by pre-conditioning the formation around the wellbores and promoting spontaneous ignition. The ISC process, also known as fire flooding or fireflood, is sustained and the ISC fire front moves due to the continuous injection of the oxidizing gas. The heat generated by burning the heavy hydrocarbons in place produces hydrocarbon cracking, vaporization of light hydrocarbons and reservoir water in addition to the deposition of heavier hydrocarbons known as coke. As the fire moves, the burning front pushes a mixture of hot combustion gases, steam, and hot water, which in turn reduces oil viscosity and the oil moves toward the production well. Additionally, the light hydrocarbons and the steam move ahead of the burning front, condensing into liquids, facilitating miscible displacement and hot water flooding, which contribute to the recovery of hydrocarbons.

Canadian Patent 2,096,034 to Kisman et al. and U.S. Pat. No. 5,211,230 to Ostapovich et al. disclose a method of in situ combustion for the recovery of hydrocarbons from underground reservoirs, sometimes referred to as Combustion Split production Horizontal well Process (COSH) or Combustion Overhead Gravity Drainage (COGD). The disclosed processes include gravity drainage to a basal horizontal well in a combustion process. A horizontal production well is located in the lower portion of the reservoir. A vertical injection and one or more vertical vent wells are provided in the upper portion of the reservoir. Oxygen-enriched gas is injected down the injector well and ignited in the upper portion of the reservoir to create a combustion zone that reduces viscosity of oil in the reservoir as the combustion zone advances downwardly toward the horizontal production well. The reduced-viscosity oil drains into the horizontal production well under the force of gravity.

Canadian Patent 2,678,347 to Bailey discloses a pre-ignition heat cycle (PIHC) using cyclic steam injection and steam flood methods that improve the recovery of viscous hydrocarbons from a subterranean reservoir using an overhead in situ combustion process, referred to as combustion overhead gravity drainage (COGD). Bailey discloses a method where the reservoir well network includes one or more injection wells and one or more vent wells located in the top portion of the reservoir, and where the horizontal drain is located in the bottom portion of the reservoir.

The use of ISC as a follow up process to SAGD is disclosed in Canadian Patent 2,594,414 to Chhina et al. The disclosed hydrocarbon recovery processes may be utilized in hydrocarbon reservoirs. Chhina discloses a process where a former steam injection well, used during the preceding SAGD recovery process, is used as an oxidizing gas injection well and where another former steam injection well, adjacent to the oxidizing gas injection well, is converted into a combustion gas production well. This results in the horizontal hydrocarbon production well being located below the horizontal oxidizing gas injection well and at least one combustion gas production well being spaced from the injection well by a distance that is greater than the spacing between hydrocarbon production well and the oxidizing gas injection well. Since the process disclosed by Chhina uses at least two wells pairs, ISC is initiated after the production well is sufficiently depleted of hydrocarbons to establish communication between the two well pairs.

At the end of thermal based hydrocarbon recovery processes there is residual energy stored in the bitumen-depleted reservoir. In the case of steam-based recovery processes, this energy is the result of steam injection in the reservoir during the life time of the process. In the case of combustion-based recovery processes, this energy is the result of the heat of the combustion used to produce the hydrocarbons. It is desirable to recover thermal energy from hydrocarbon reservoir that has a hot bitumen-depleted zone.

SUMMARY

In a first aspect, the present disclosure provides a method of producing heated water from a hydrocarbon reservoir having a hot bitumen-depleted zone. The method includes injecting water into at least a portion of the hot bitumen-depleted zone to heat the water; and producing the heated water from a heated water production well.

The method may also include generating the hot bitumen-depleted zone using steam-assisted gravity drainage, in situ combustion, steam flooding, cyclic steam stimulation, a solvent aided thermal recovery process, electric heating, electromagnetic heating, or any combination thereof.

Injecting the water into at least a portion of the hot bitumen-depleted zone may heat the water sufficiently to generate steam in situ. The heated water production well may be located above at least a portion of the hot bitumen-depleted zone, and the water may be injected into the portion of the hot-bitumen depleted zone below the heated water production well.

Injecting the water into at least a portion of the hot bitumen-depleted zone may heat the water sufficiently to generate hot liquid water in situ. The heated water production well may be located below at least a portion of the hot bitumen-depleted zone, and the water may be injected into the portion of the hot-bitumen depleted zone above the heated water production well.

Injecting the water into at least a portion of the hot bitumen-depleted zone may heat the water sufficiently to generate both steam and hot liquid water in situ. Heated water may be produced from a first and a second heated water production well, where the first heated water production well is located above at least a portion of the hot bitumen-depleted zone; and the second heated water production well is located below at least a portion of the hot bitumen-depleted zone. The water may be injected into a portion of the hot-bitumen depleted zone below the first heated water production well and above the heated water production well. In such a situation, the first heated water production well may produce heated water from the generated steam, and the second heated water production well may produce heated water from the generated hot liquid water.

Some embodiments described herein include a method of producing heated water from a hydrocarbon reservoir, the method comprising injecting water into at least a portion of the hot bitumen-depleted zone to heat the water; and producing the heated water from a heated water production well.

In some embodiments, the method further comprises generating the hot bitumen-depleted zone using steam-assisted gravity drainage, in situ combustion, steam flooding, cyclic steam stimulation, a solvent aided thermal recovery process, electric heating, electromagnetic heating, or any combination thereof.

In some embodiments, injecting the water into at least a portion of the hot bitumen-depleted zone heats the water sufficiently to generate steam in situ.

In some embodiments, the heated water production well is located above at least a portion of the hot bitumen-depleted zone, and the water is injected into the portion of the hot-bitumen depleted zone below the heated water production well.

In some embodiments, injecting the water into at least a portion of the hot bitumen-depleted zone heats the water sufficiently to generate hot liquid water in situ.

In some embodiments, the heated water production well is located below at least a portion of the hot bitumen-depleted zone, and the water is injected into the portion of the hot-bitumen depleted zone above the heated water production well.

In some embodiments, injecting the water into at least a portion of the hot bitumen-depleted zone heats the water sufficiently to generate both steam and hot liquid water in situ.

In some embodiments, the method comprises producing heated water from a first and a second heated water production well, wherein the first heated water production well is located above at least a portion of the hot bitumen-depleted zone; and the second heated water production well is located below at least a portion of the hot bitumen-depleted zone; and the water is injected into a portion of the hot-bitumen depleted zone below the first heated water production well and above the heated water production well, and the first heated water production well produces heated water from the generated steam, and the second heated water production well produces heated water from the generated hot liquid water.

Other aspects and features of the present disclosure will become apparent to those ordinarily skilled in the art upon review of the following description of specific embodiments in conjunction with the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures. The patent or application file contains at least one drawing executed in color, Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee,

FIG. 1 is an illustration of a first simulated reservoir.

FIG. 2 is an illustration of the temperature profile of the first simulated reservoir after 4 years of SAGD.

FIG. 3 is an illustration of the temperature profile of the first simulated reservoir after 1 year of injection of methane.

FIG. 4 is an illustration of the temperature profile of the first simulated reservoir after 2.28 years of injection of water.

FIG. 5 is a graph showing the cumulative energy injected and produced for the first simulated reservoir.

FIG. 6 is a graph showing the energy distribution at different stages of the process for the first simulated reservoir.

FIG. 7 is an illustration of a second simulated reservoir.

FIG. 8 is an illustration of the temperature profile of the second simulated reservoir after 4 years of SAGD.

FIG. 9 is an illustration of the temperature profile of the second simulated reservoir after 1 year of injection of methane.

FIG. 10 is an illustration of the temperature profile of the second simulated reservoir after 3.31 years of injection of water.

FIG. 11 is a graph showing the cumulative energy injected and produced for the second simulated reservoir.

FIG. 12 is a graph showing the energy distribution at different stages of the process for the second simulated reservoir.

FIG. 13 is an illustration of a third simulated reservoir.

FIG. 14 is an illustration of the temperature profile of the third simulated reservoir after 4 years of SAGD.

FIG. 15 is an illustration of the temperature profile of the third simulated reservoir after 1 year of injection of methane.

FIG. 16 is an illustration of the temperature profile of the third simulated reservoir after 5.82 years of injection of water.

FIG. 17 is a graph showing the cumulative energy injected and produced for the third simulated reservoir.

FIG. 18 is a graph showing the energy distribution at different stages of the process for the third simulated reservoir.

FIG. 19 is an illustration of a fourth simulated reservoir.

FIG. 20 is an illustration of the temperature profile of the fourth simulated reservoir after 3.6 years of SAGD.

FIG. 21 is an illustration of the temperature profile of the fourth simulated reservoir after 2 year of injection of butane.

FIG. 22 is an illustration of the temperature profile of the fourth simulated reservoir after 1.2 years of injection of water.

FIG. 23 is a graph showing the cumulative energy injected and produced for the fourth simulated reservoir.

FIG. 24 is an illustration of a fifth simulated reservoir.

FIG. 25 is an illustration of the temperature profile of the fifth simulated reservoir after 3.6 years of SAGD.

FIG. 26 is an illustration of the temperature profile of the fifth simulated reservoir after 2 year of injection of butane.

FIG. 27 is an illustration of the temperature profile of the fifth simulated reservoir after 3.8 years of injection of water.

FIG. 28 is a graph showing the cumulative energy injected and produced for the fifth simulated reservoir.

FIG. 29 is a graph showing the energy distribution at different stages of the process for the fifth simulated reservoir.

FIG. 30 is an illustration of a sixth simulated reservoir.

FIG. 31 is an illustration of the temperature profile of the sixth simulated reservoir after 5 years of SAGD and 4.5 years of in situ combustion.

FIG. 32 is an illustration of the temperature profile of the sixth simulated reservoir after 0.3 years of injection of water.

FIG. 33 is an illustration of the temperature profile of the sixth simulated reservoir after 0.9 years of injection of water.

FIG. 34 is an illustration of the temperature profile of the sixth simulated reservoir after 1.5 years of injection of water.

FIG. 35 is a graph showing the cumulative energy injected and produced for the sixth simulated reservoir.

FIG. 36 is a graph showing the energy distribution at different stages of the process for the sixth simulated reservoir.

DETAILED DESCRIPTION

Generally, the present disclosure provides a method of producing heated water from a hydrocarbon reservoir having a hot bitumen-depleted zone. The method includes: injecting water into at least a portion of the hot bitumen-depleted zone to heat the water; and producing the heated water from a heated water production well. The water may be injected using an injection well.

It is not necessary that the bitumen-depleted zone be completely depleted of bitumen. Accordingly, in the context of the present application, a bitumen-depleted zone would be understood to refer to a zone in the hydrocarbon reservoir where it is not commercially viable to continue to extract bitumen from the hydrocarbon reservoir, even though residual bitumen may be present in the hydrocarbon reservoir. In some hydrocarbon reservoirs, it may no longer be commercially viable to extract bitumen once the average residual oil saturation level is less than 40%. In other hydrocarbon reservoirs, it may no longer be commercially viable to extract bitumen once the average residual oil saturation level is less than 30%. In yet other hydrocarbon reservoirs, it may no longer be commercially viable to extract bitumen once the average residual oil saturation level is less than 20%. In some especially productive hydrocarbon reservoirs, it may no longer be commercially viable to extract bitumen once the average residual oil saturation level is less than 10-15%.

A hot bitumen-depleted zone is to be understood to refer to a bitumen-depleted zone whose temperature is elevated by heat used in a thermal bitumen-recovery process that generates the bitumen-depleted zone. In particular examples, the hot bitumen-depleted zone is generated by steam-assisted gravity drainage, in situ combustion, a solvent aided thermal recovery process, electric heating, electromagnetic heating, or any combination thereof.

In some examples, the hot bitumen-depleted zone has an average temperature of at least 10° C. For example, the hot bitumen-depleted zone may have an average temperature of between 20 and 300° C. when the hot bitumen-depleted zone is generated by steam-assisted gravity drainage. In another example, the hot bitumen-depleted zone may have an average temperature of between 20 and 600° C. when the hot bitumen-depleted zone is generated by in situ combustion. In yet another example, the hot bitumen-depleted zone may have an average temperature of between 20 and 400° C. when the hot bitumen-depleted zone is generated by electromagnetic heating.

Regardless of the thermal bitumen recovery method used to generate the hot bitumen-depleted zone, some hot bitumen-depleted zones may have conditions that generate steam from the water, while other hot bitumen-depleted zones may have conditions that generate hot liquid water. A hot bitumen-depleted zone may, at a specific point in time, have conditions that generate steam, and, at a later point in time, may have conditions that generate hot liquid water.

When generating steam in the hot bitumen-depleted zone, it is desirable to place the heated water production well above at least a portion of the hot bitumen-depleted zone. In such a manner, the water that is injected into the portion of the hot-bitumen depleted zone below the heated water production well may be turned into steam, which rises up to the heated water production well.

It is not necessary for the heated water production well to be placed above at least a portion of the hot bitumen-depleted zone. Steam may be driven from an upper portion of the hot bitumen-depleted zone downwards to a heated water production well placed below at least a portion of the hot bitumen-depleted zone. Alternatively, steam may be driven substantially across a portion of the hot bitumen-depleted zone to a heated water production well that is at substantially the same level as the liquid water injection well. The steam may be produced from the heated water production well as steam or as hot liquid water.

When generating hot liquid water in the hot bitumen-depleted zone, it is desirable to place the heated water production well below at least a portion of the hot bitumen-depleted zone. In such a manner, the water that is injected into the portion of the hot-bitumen depleted zone above the heated water production well may be turned into hot liquid water, which descends due to gravity to the heated water production well.

It is not necessary for the heated water production well to be placed below at least a portion of the hot bitumen-depleted zone. Liquid water may be driven from a lower portion of the hot bitumen-depleted zone upwards to a heated water production well placed above at least a portion of the hot bitumen-depleted zone. Alternatively, liquid water may be driven substantially across a portion of the hot bitumen-depleted zone to a heated water production well that is at substantially the same level as the liquid water injection well.

In some examples, injecting the liquid water in at least a portion of the hot bitumen-depleted zone may heat the water sufficiently to generate both steam and hot liquid water in situ. When generating both steam and hot liquid water, the method may include producing heated water from a first and a second heated water production well. In such situations, the first heated water production well is located above at least a portion of the hot bitumen-depleted zone; and the second heated water production well is located below at least a portion of the hot bitumen-depleted zone. The water is injected into a portion of the hot-bitumen depleted zone below the first heated water production well and above the heated water production well, and the first heated water production well produces heated water from the generated steam, and the second heated water production well produces water from the generated hot liquid water.

In the context of the presently disclosure, when referring to ‘injecting water’, the term “water” should be understood to refer to a generally aqueous solution that is injected into at least a portion of the hot bitumen-depleted zone. The generally aqueous solution may include salts, non-aqueous solvents that are soluble in water, or both. The generally aqueous solution may be mixed with one or more non-aqueous solvents that are not soluble in water. The expression “injecting water” should be understood to also include injecting this mixture into at least a portion of the hot bitumen-depleted zone.

The expression “heated water” should be understood to mean water that is at a temperature higher than the temperature of the injected water. Heated water may be liquid water, or steam. The steam may be saturated steam (or “wet steam”), or superheated steam (or “dry steam”). Saturated steam could be considered to be a mixture of liquid water and water vapor.

Since both temperature and pressure affect whether the heated water is a hot liquid water or steam, water that is injected into a hot bitumen-depleted zone as liquid water may be produced at the heated water production well as steam. Accordingly, it is the conditions in the hot bitumen-depleted zone that would determine whether steam or hot liquid water is being driven through the portion of the hot-bitumen depleted zone. In the context of the present disclosure, it should be understood that reservoir conditions may promote the co-existence of both steam and liquid water. It should be understood that the term “steam” includes: water vapor in a vapor-liquid equilibrium (also referred to as “saturated steam” or “wet steam”), and a water vapor that is at a temperature higher than its boiling point for the pressure, which occurs when all the liquid water has evaporated or has been removed from the system (also referred to as “superheated steam” or “dry steam”).

Hot bitumen-depleted zones that have conditions that generate steam in the hot bitumen-depleted zone may, after thermal energy is removed from the hot bitumen-depleted zone, have conditions that generate hot liquid water in the hot bitumen-depleted zone. The method may use a first heated water production well that is located above at least a portion of the hot bitumen-depleted zone when the hot bitumen-depleted zone has conditions that generate steam, and a second heated water production well that is located below at least a portion of the hot bitumen-depleted zone when the hot bitumen-depleted zone has conditions that generate hot liquid water.

EXAMPLE 1

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 1. The SAGD pattern is a two-dimensional model whose dimensions are 50 m×2 m×24 m. These dimensions correspond to a horizontal well pair that is 2 m long with a 24 m pay thickness and a 100 m lateral well spacing. However, only half of the reservoir was simulated due to symmetry, with the SAGD well pair on the left and the water injection well on the right of the model. Additionally, only 2 m of well pair length were simulated as the model is 2-dimensional.

1500 grid blocks were used as this number was adequate enough to build an accurate model. The dimensions for each of these blocks are 1 m×2 m×0.8 m in the X, Y, and Z directions respectively. The SAGD injection well was placed 4 m above the SAGD producing well which is located at the bottom of the reservoir.

Table 1 shows the reservoir and fluid parameters used in the simulation.

TABLE 1

Average Gross Pay (m)
24

Porosity (%)
0.33

Bitumen Saturation (%)
0.8

Water Saturation (%)
0.2

Vertical Permeability (mD)
4000

K_v/K_h
0.8

Viscosity (mPa · s) at 20° C.
2,670,000

Bitumen Density (kg/m³) at 20° C.
1014.8

Reservoir Temperature (° C.)
11

Reservoir Pressure (kPa)
2200

Table 2 shows the injection rates used in the simulation, where the *'ed entries assume a 700 m length well pair.

TABLE 2

Steam injection (CWE) t/d
0.65
455*

Methane injection t/d
0.0057
4*

Cold water injection t/d
1.5
1050*

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 4 years. After the 4 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 65.2%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 2. The temperature ranges from 228° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

At the end of 4 years, methane is injected for a period of 1 year in order to continue to produce hydrocarbon without injecting additional heat into the reservoir. This may be referred to as “methane blowdown”. After the 1 year of injection of methane, the hydrocarbon recovery factor is 71.4%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 3.

After injection of methane, water is injected for a period of 2.28 years. The water is injected into a portion of the hot bitumen-depleted zone that is above the heated water production well and heated water is produced from what was previously the SAGD producing well. After the 2.28 years of injection of water, the hydrocarbon recovery factor is 72.9%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 4.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 5. The energy distribution at different stages of the process is illustrated in FIG. 6. The energy recovered between blow-down and the end of water injection (4.53e8 kJ) represents 57.6% of the energy accumulated at blow-down (7.859e8 kJ).

EXAMPLE 2

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 7. The reservoir initial parameters were the same as in Example 1. Only half of the reservoir was simulated due to symmetry, with the water injection well located on the top right and two SAGD well pairs.

Table 3 shows the injection rates used in the simulation, where the *'ed entries assume a 700 m length well pair.

TABLE 3

Steam injection (CWE) t/d
1.95
1365*

Methane injection t/d
0.0171
11.97*

Cold water injection t/d
4
2800*

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 4 years. After the 4 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 64.2%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 8. The temperature ranges from 233° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

At the end of 4 years, methane is injected for a period of 1 year in order to continue to produce hydrocarbon without injecting additional heat into the reservoir. This may be referred to as “methane blowdown”. After the 1 year of injection of methane, the hydrocarbon recovery factor is 72.9%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 9.

After injection of methane, water is injected for a period of 3.31 years. The water is injected into a portion of the hot bitumen-depleted zone that is above the heated water production well and heated water is produced from what was previously the SAGD producing well. Water is injected into the well located at the upper corners of the reservoir. When the temperature of the produced water in the outer producing wells decreased to 90° C., these wells were closed. In this simulation, the first SAGD well pair is shut-in at 6.16 years (i.e. after 1.16 years of water injection). Water continues to be injected and is produced through the middle producer until T=90° C. After the 3.31 years of injection of water, the hydrocarbon recovery factor is 73.7%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 10.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 11. The energy distribution at different stages of the process is illustrated in FIG. 12. The energy recovered between blow-down and the end of water injection (1.88e9 kJ) represents 77.36% of the energy accumulated at blow-down (2.43e9 kJ).

EXAMPLE 3

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 13. The full reservoir was simulated due to asymmetry, with the water injection well located on the top right and the heated water production well located on the top left. The SAGD pattern is a two-dimensional model whose dimensions are 300 m×2 m×24 m. These dimensions correspond to a horizontal well pair that is 2 m long with a 24 m pay thickness and a 100 m lateral well spacing. 9000 grid blocks were used as this number was adequate enough to build an accurate model. The dimensions for each of these blocks are 1 m×1 m×0.8 m in the X, Y, and Z directions respectively.

Table 4 shows the injection rates used in the simulation, where the *'ed entries assume a 700 m length well pair.

TABLE 4

Steam injection (CWE) t/d
3.9
1365*

Methane injection t/d
0.0342
11.97*

Cold water injection t/d
3-5
1050-1750*

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 4 years. After the 4 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 64.6%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 14. The temperature ranges from 233° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

At the end of 4 years, methane is injected for a period of 1 year in order to continue to produce hydrocarbon without injecting additional heat into the reservoir. This may be referred to as “methane blowdown”. After the 1 year of injection of methane, the hydrocarbon recovery factor is 73.4%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 15.

After injection of methane, water is injected into the water injection well at the top right, and produced from the heated water production well at the top left, for a period of 5.82 years. After the 5.82 years of injection of water, the hydrocarbon recovery factor is 73.44%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 16.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 17. The energy distribution at different stages of the process is illustrated in FIG. 18. The energy recovered between blow-down and the end of water injection (4.32e9 kJ) represents 88.5% of the energy accumulated at blow-down (4.88e9 kJ).

EXAMPLE 4

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 19. The SAGD pattern is a two-dimensional model whose dimensions are 50 m×2 m×24 m. These dimensions correspond to a horizontal well pair that is 2 m long with a 24 m pay thickness and a 100 m lateral well spacing. However, only half of the reservoir was simulated due to symmetry, with the SAGD well pair on the left and the water injection well on the right of the model. Additionally, only 2 m of well pair length were simulated as the model is 2-dimensional.

Table 5 shows the reservoir and fluid parameters used in the simulation.

TABLE 5

Average Gross Pay (m)
24

Porosity (%)
0.33

Bitumen Saturation (%)
0.8

Water Saturation (%)
0.2

Vertical Permeability (mD)
4000

K_v/K_h
0.8

Viscosity (mPa · s) at 20° C.
2,670,000

Bitumen Density (kg/m³) at 20° C.
1014.8

Reservoir Temperature (° C.)
11

Reservoir Pressure (kPa)
2200

Table 6 shows the injection rates used in the simulation, where the asterisked entries assume a 700 m length well pair.

TABLE 6

Steam injection (CWE) t/d
0.65
455*

Butane injection t/d
0.0057
4*

Cold water injection t/d
1.5
1050*

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 3.6 years. After the 3.6 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 60.7%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 20. The temperature ranges from 234° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

At the end of 3.6 years, butane is injected for a period of 2 years in order to continue to produce hydrocarbon without injecting additional heat into the reservoir. This may be referred to as “butane blowdown”. After the 2 year of injection of butane, the hydrocarbon recovery factor is 83.7%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 21.

After injection of methane, water is injected for a period of 1.2 years. The water is injected into a portion of the hot bitumen-depleted zone that is above the heated water production well and heated water is produced from what was previously the SAGD producing well. After the 1.2 years of injection of water, the hydrocarbon recovery factor is 83.7%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 22.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 23. The energy recovered between blow-down and the end of water injection (2.92e8 kJ) represents 43.5% of the energy accumulated at blow-down (7.71e8 kJ).

EXAMPLE 5

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 24. The reservoir initial parameters were the same as in Example 2, except that butane is injected at a rate of 0.195 t/d (10% of the steam injection rate), which is higher than the rate of methane injection to account for the larger simulated reservoir. Only half of the reservoir was simulated due to symmetry, with the water injection well located on the top right and two SAGD well pairs.

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 3.6 years. After the 3.6 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 60.2%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 25. The temperature ranges from 239° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

At the end of 3.6 years, butane is injected for a period of 2 years in order to continue to produce hydrocarbon without injecting additional heat into the reservoir. This may be referred to as “butane blowdown”. After the 2 year of injection of butane, the hydrocarbon recovery factor is 81.1%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 26.

After injection of butane, water is injected for a period of 3.8 years. The water is injected into a portion of the hot bitumen-depleted zone that is above the heated water production well and heated water is produced from what was previously the SAGD producing well. Water is injected into the well located at the upper corners of the reservoir. When the temperature of the produced water in the outer producing wells decreased to 90° C., these wells were closed. In this simulation, the first SAGD well pair is shut-in at 6.25 years (i.e. after 0.65 years of water injection). Water continues to be injected and is produced through the middle producer until T=90° C. After the 3.8 years of injection of water, the hydrocarbon recovery factor is 81.1%. The temperature profile of the simulated hot bitumen depleted zone is shown in FIG. 27.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 28. The energy distribution at different stages of the process is illustrated in FIG. 29. The energy recovered between blow-down and the end of water injection (1.59e9 kJ) represents 79.5% of the energy accumulated at blow-down (2.00e9 kJ).

EXAMPLE 6

A simulation of a process according to the present disclosure reservoir was performed.

An illustration of the simulated reservoir is shown in FIG. 30. The reservoir initial parameters were the same as in Example 5. Only a third of the reservoir was simulated due to symmetry, with two oxidizing gas injector wells located on the top corners and one SAGD well pair located at the bottom center.

In the simulation, bitumen is produced via steam-assisted gravity drainage for a period of 5 years. After the 5 years of SAGD operation, steam injection is ended and the hydrocarbon recovery factor is 68.74%.

At the end of 5 years, oxidizing gas is injected for a period of 4.5 years in order to produce hydrocarbons through in-situ combustion. After the 4.5 years of in-situ combustion, oxidizing gas injection is ended and the hydrocarbon recovery factor is 75.43%.

After injection of oxidizing gas, water is injected for a period of 1.5 years. The water is injected into a portion of the hot bitumen-depleted zone through the former SAGD injection wells and heated water is produced from the former oxidizing gas injection wells as steam. After the 1.5 years of injection of water, the hydrocarbon recovery factor is 75.43%.

The temperature profile of the simulated hot bitumen depleted zone after 9.5 years, corresponding to the reservoir after in situ combustion but before injection of water, is shown in FIG. 31. The temperature ranges from 1245° C. to 11° C. with color indicating the temperature in each simulated cell. Red represents hotter temperatures and blue represents cooler temperatures.

Temperature profiles of the simulated hot bitumen depleted zone after 9.8 and 10.4 years, corresponding to the reservoir at two points during heat recovery, are shown in FIGS. 32 and 33. In FIG. 32, the temperature ranges from 900° C. to 11° C. In FIG. 33, the temperature ranges from 300° C. to 11° C. The temperature profile of the simulated hot bitumen depleted zone after 11 years, corresponding to the reservoir at the end of the heat recovery phase, is shown in FIG. 34.

The cumulative energy injected and produced for the simulation is illustrated in FIG. 35. The energy distribution at different stages of the process is illustrated in FIG. 36. The energy recovered between in-situ combustion and the end of water injection (1.353e9 kJ) represents 92.5% of the energy accumulated at the end of in situ combustion (1.463e9 kJ).

In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the examples. However, it will be apparent to one skilled in the art that these specific details are not required. The above-described examples are intended to be exemplary only. Alterations, modifications and variations can be effected to the particular examples by those of skill in the art without departing from the scope, which is defined solely by the claims appended hereto.

WASTE HEAT RECOVERY FROM DEPLETED RESERVOIR

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