CA3060757C - Sustainable enhanced oil recovery of heavy oil method and system - Google Patents
Sustainable enhanced oil recovery of heavy oil method and system Download PDFInfo
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- CA3060757C CA3060757C CA3060757A CA3060757A CA3060757C CA 3060757 C CA3060757 C CA 3060757C CA 3060757 A CA3060757 A CA 3060757A CA 3060757 A CA3060757 A CA 3060757A CA 3060757 C CA3060757 C CA 3060757C
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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
Abstract
A method for recovering heavy oil from a subterranean formation that has undergone a previous formation process. The method can include utilizing an injection well, and a vertically displaced combustion well. Water is injected into the formation from the first well, and a fuel and air or oxygen are introduced into an interior of the second well for combustion. The resulting combustion gas travels into the formation to contact the water to create steam. The combustion gas and the steam repressurize and heat the formation to mobilize any existing oil toward laterally offset production wells. Wormholes created by the previous process are collapsed by the combustion gas and/or steam to block the conduit and to increase permeability of the surrounding formation.
Description
Docket No.: 205-19 TITLE OF THE INVENTION
SUSTAINABLE ENHANCED OIL RECOVERY OF HEAVY OIL METHOD AND SYSTEM
BACKGROUND OF THE INVENTION
.. TECHNICAL FIELD
The present technology relates to a sustainable enhanced oil recovery of heavy oil (SEOR) method and system for use in connection with producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation. The heavy oil formation or reservoir may have undergone primary production using pressure depletion with or without sand production, bottom water drive, top gas drive or by waterflooding.
DESCRIPTION OF THE BACKGROUND ART
Heavy oil production using pressure depletion of the reservoir with and without sand is known in the prior art as Cold Heavy Oil Production (CHOP) or Cold Heavy Oil Production with Sand (CHOPS). CHOP is the primary production of heavy oil using vertical wells and/or horizontal wells. When heavy oil is produced using vertical wells, the oil is produced with reservoir sand, is foamy with gas, and reservoir pressure decreases significantly. In the reservoir, the sand is extracted through a single, multiple or network conduits know as wormholes.
The oil becomes foamy with gas in the reservoir and flows into the wormholes then to the vertical well bore. The wormholes continue to grow in length towards the higher pressure regions of the reservoir.
Eventually, the wormholes will be unable to grow further due to significant reservoir pressure depletion. The production will have declined significantly to an uneconomic level resulting in the shut in of the well. The recoverable amount of oil is usually about only 5-10%
of the original oil in place. The state of the reservoir is the existence of these wormholes or conduits, connected gas saturation of about 6-12% of the pore volume and extremely low reservoir pressure. Gas saturation increases to replace the produced oil and sand. Eventually, the reservoir pressure declines to a low pressure such that the wells are no longer productive. This is known as CHOP
production with sand or CHOPS.
Initially in CHOP, the reservoir could be in a pressure range of 4000-8000 kPag with no gas saturation. With depleted CHOP production, gas saturation increases to 6-12%
and pressure depletes to less than 1000 kPag.
Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Another method of CHOP production is using horizontal wells with slotted liners to prevent sand production. The oil becomes foamy with gas as it flows from the reservoir into the lower pressure liner of the well. The reservoir pressure decreases with production.
Likewise, the production decreases with reservoir pressure to an uneconomic level resulting in the shut in of the well. The recoverable amount of oil is usually about only 5-10% of the original oil in place. The state of the reservoir is a connected gas saturation of about 6-12% of the pore volume and extremely low reservoir pressure. This is known as CHOP production with horizontal wells and without sand.
After CHOP production, the remaining oil is essentially immobile due to the low reservoir pressure, low dissolved or solution gas, and much higher viscosity.
Another method of producing the lower viscosity heavy oil is to use waterflooding.
Waterflooding involves injecting water into one or more wells, and produce both oil and water from nearby one or more wells. Water flows laterally and mostly horizontally from the injection wells dragging some heavy oil with it to the producing wells. Some of the injected water could channel to the producing wells. The injected water and the dragged heavy oil is produced from the producing wells. Waterflooding can also occur naturally when the heavy oil is underlain by a water aquifer.
In this situation, the bottom water pushes the oil upwards to the producing well and causes water cones to form. There is also another situation where there is a gas zone above the oil. The top gas will push the oil downwards to the producing well and causes gas cones to form. In all these situations, water or gas production increases and oil production will decrease to an uneconomic level resulting in the shut in of the well.
The ultimate recovery of heavy oil using waterflooding usually amounts to 10-25% of the original oil in place.
An enhanced oil recovery method that can be added to horizontal waterflooding is chemical flooding. These chemicals are alkaline, surfactant or polymers or ASP. These chemicals can be .. added singularly or in combination. This method can increase recovery level by 5-10% of original oil in place.
Where the reservoir thickness of the heavy oil is well above 10 meter, thermal production method using steam injection can be economic. These thermal methods are known as steam flooding, cyclic steam stimulation or Steam Assisted Gravity Drainage (SAGD).
The SAGD
method can be enhanced using solvent and is known as solvent SAGD. These thermal production methods are disadvantaged with high costs, emissions of carbon dioxide and other oxides to the atmosphere and the need of make-up water for steam generation.
SUSTAINABLE ENHANCED OIL RECOVERY OF HEAVY OIL METHOD AND SYSTEM
BACKGROUND OF THE INVENTION
.. TECHNICAL FIELD
The present technology relates to a sustainable enhanced oil recovery of heavy oil (SEOR) method and system for use in connection with producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation. The heavy oil formation or reservoir may have undergone primary production using pressure depletion with or without sand production, bottom water drive, top gas drive or by waterflooding.
DESCRIPTION OF THE BACKGROUND ART
Heavy oil production using pressure depletion of the reservoir with and without sand is known in the prior art as Cold Heavy Oil Production (CHOP) or Cold Heavy Oil Production with Sand (CHOPS). CHOP is the primary production of heavy oil using vertical wells and/or horizontal wells. When heavy oil is produced using vertical wells, the oil is produced with reservoir sand, is foamy with gas, and reservoir pressure decreases significantly. In the reservoir, the sand is extracted through a single, multiple or network conduits know as wormholes.
The oil becomes foamy with gas in the reservoir and flows into the wormholes then to the vertical well bore. The wormholes continue to grow in length towards the higher pressure regions of the reservoir.
Eventually, the wormholes will be unable to grow further due to significant reservoir pressure depletion. The production will have declined significantly to an uneconomic level resulting in the shut in of the well. The recoverable amount of oil is usually about only 5-10%
of the original oil in place. The state of the reservoir is the existence of these wormholes or conduits, connected gas saturation of about 6-12% of the pore volume and extremely low reservoir pressure. Gas saturation increases to replace the produced oil and sand. Eventually, the reservoir pressure declines to a low pressure such that the wells are no longer productive. This is known as CHOP
production with sand or CHOPS.
Initially in CHOP, the reservoir could be in a pressure range of 4000-8000 kPag with no gas saturation. With depleted CHOP production, gas saturation increases to 6-12%
and pressure depletes to less than 1000 kPag.
Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Another method of CHOP production is using horizontal wells with slotted liners to prevent sand production. The oil becomes foamy with gas as it flows from the reservoir into the lower pressure liner of the well. The reservoir pressure decreases with production.
Likewise, the production decreases with reservoir pressure to an uneconomic level resulting in the shut in of the well. The recoverable amount of oil is usually about only 5-10% of the original oil in place. The state of the reservoir is a connected gas saturation of about 6-12% of the pore volume and extremely low reservoir pressure. This is known as CHOP production with horizontal wells and without sand.
After CHOP production, the remaining oil is essentially immobile due to the low reservoir pressure, low dissolved or solution gas, and much higher viscosity.
Another method of producing the lower viscosity heavy oil is to use waterflooding.
Waterflooding involves injecting water into one or more wells, and produce both oil and water from nearby one or more wells. Water flows laterally and mostly horizontally from the injection wells dragging some heavy oil with it to the producing wells. Some of the injected water could channel to the producing wells. The injected water and the dragged heavy oil is produced from the producing wells. Waterflooding can also occur naturally when the heavy oil is underlain by a water aquifer.
In this situation, the bottom water pushes the oil upwards to the producing well and causes water cones to form. There is also another situation where there is a gas zone above the oil. The top gas will push the oil downwards to the producing well and causes gas cones to form. In all these situations, water or gas production increases and oil production will decrease to an uneconomic level resulting in the shut in of the well.
The ultimate recovery of heavy oil using waterflooding usually amounts to 10-25% of the original oil in place.
An enhanced oil recovery method that can be added to horizontal waterflooding is chemical flooding. These chemicals are alkaline, surfactant or polymers or ASP. These chemicals can be .. added singularly or in combination. This method can increase recovery level by 5-10% of original oil in place.
Where the reservoir thickness of the heavy oil is well above 10 meter, thermal production method using steam injection can be economic. These thermal methods are known as steam flooding, cyclic steam stimulation or Steam Assisted Gravity Drainage (SAGD).
The SAGD
method can be enhanced using solvent and is known as solvent SAGD. These thermal production methods are disadvantaged with high costs, emissions of carbon dioxide and other oxides to the atmosphere and the need of make-up water for steam generation.
- 2 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 The use of steam environmentally generated drainage (SEGD) system and method may be known to one skilled in the art as described in U.S. issued patent 9,435,183 and Canadian issued patent 2,867,328. SEGD is used in connection with producing hydrocarbons from a formation or reservoir using in situ steam generation and gravity drainage utilizing a first well as a circulation .. and production well, a second well as a circulation, injection and combustion well, and a third well as an injection well, as illustrated in FIGS. 1-4. The first, second and third wells being vertically displaced from each other in a hydrocarbon reservoir. The second well is configurable to create an in situ combustion by having a slotted liner defining a plurality of bores, and including therein an igniter, a fuel tubing, and a gas tubing. The fuel tubing and the gas tubing each has at least one port configured to deliver a flow into an interior of the slotted liner. The igniter is configured to ignite the flow from the fuel tubing and the gas tubing to create the in situ combustion within the slotted liner. The third well is configured to inject a vaporizing fluid into the hydrocarbon reservoir so that it is vaporized by the in situ combustion upon contact with combustion gases.
The use of steam assisted gravity drainage (SAGD) systems is known in the prior art.
Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. It is an important issue to develop more efficient recovery, processing and/or use of available hydrocarbon resources, while increasing safety to personnel and protecting the surrounding environment. In situ processes may be used to remove hydrocarbon materials, such as bitumen, from subterranean formations that were previously inaccessible and/or too expensive to extract using available methods. To efficiently and effectively extract hydrocarbon material from subterranean formations, the chemical and/or physical properties of the hydrocarbon material may need to be altered to allow the hydrocarbon material to be more easily flow through the formation. The systems and methods associated with these changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation.
Further disadvantages of utilizing SEGD or SAGD is the limitation of these gravity drainage processes is its handling of high steam quantities, particularly for thin and low-quality oil fields, where heat losses due to overburden are larger. Likewise, handling of these steam requirements for SAGD needs an enormous source of fresh water, an issue that may sometimes become an obstacle.
.. Additionally, as in most steam injection process methods, efforts are limited by oil-well depths, as imposed by steam's critical pressure.
The use of steam assisted gravity drainage (SAGD) systems is known in the prior art.
Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products. It is an important issue to develop more efficient recovery, processing and/or use of available hydrocarbon resources, while increasing safety to personnel and protecting the surrounding environment. In situ processes may be used to remove hydrocarbon materials, such as bitumen, from subterranean formations that were previously inaccessible and/or too expensive to extract using available methods. To efficiently and effectively extract hydrocarbon material from subterranean formations, the chemical and/or physical properties of the hydrocarbon material may need to be altered to allow the hydrocarbon material to be more easily flow through the formation. The systems and methods associated with these changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation.
Further disadvantages of utilizing SEGD or SAGD is the limitation of these gravity drainage processes is its handling of high steam quantities, particularly for thin and low-quality oil fields, where heat losses due to overburden are larger. Likewise, handling of these steam requirements for SAGD needs an enormous source of fresh water, an issue that may sometimes become an obstacle.
.. Additionally, as in most steam injection process methods, efforts are limited by oil-well depths, as imposed by steam's critical pressure.
- 3 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 In Canada, it is estimated that there is about 26 billion barrels of original oil in place of heavy oil in Saskatchewan and 12 billion barrels in Alberta. It is also estimated that 90% of the original oil in place is currently not economically recoverable primarily due to most of the heavy oil resource is in reservoir with oil thickness of less than 10 meters. Most of this resource has been produced using the CHOP, or cold heavy oil production method. These projects are reaching end of life and are urgently in need of an innovative, economic, and sustainable production method. The present technology can fulfill these needs by economically and sustainably produce oil from these pressure depleted or waterflooded reservoirs. This method mobilizes heavy oil using various mechanisms such as collapsing the wormholes, repressurizing the reservoirs with carbon dioxide, dissolving carbon dioxide (CO2) into the oil and swelling it, reducing the viscosity of the oil thermally and with dissolved CO2, and further displacing oil with CO2 and steam or hot water. This mobilized heavy oil is produced laterally from adjacent wells. Another advantage of this invention is the capturing of the combustion CO2 in the reservoir. This CO2 can be sequestered there or be used for further enhanced oil recovery.
It is known that deposits of heavy hydrocarbons contained in relatively permeable formations (for example in oil sands) are found throughout the world, and these deposits can be surface-mined and upgraded to lighter hydrocarbons. Surface mining and upgrading oil sands is an expensive process with questionable environmental impact and human health safety.
The use of in situ heating using injected steam has raised questions towards the damages to the environment and the safety to the surrounding populations and personnel working on site.
Currently, SAGD projects generate steam at surface using steam generators or boilers. These projects burn primarily natural gas to generate the steam and emit the combustion gases to the environment containing wasted heat, wasted water vapor, carbon dioxide, nitrogen oxides, sulfur oxides and other pollutants. Additional energy and steam are wasted in the equipment used to generate and transport the steam to the reservoir. They also must generate boiler quality feed water for steam generation. This requires significant amounts of make-up water and the disposal of wasted blowdown water. Consequently, by generating steam at surface, SAGD
projects waste energy and water; emits carbon dioxides and other pollutants to the environment; and require significant amounts of capital and operating expenditures.
It can be appreciated that SEGD and SAGD relies on gravity to flow mobilized hydrocarbons to a production well located a depth greater than the injection wells. These gravity
It is known that deposits of heavy hydrocarbons contained in relatively permeable formations (for example in oil sands) are found throughout the world, and these deposits can be surface-mined and upgraded to lighter hydrocarbons. Surface mining and upgrading oil sands is an expensive process with questionable environmental impact and human health safety.
The use of in situ heating using injected steam has raised questions towards the damages to the environment and the safety to the surrounding populations and personnel working on site.
Currently, SAGD projects generate steam at surface using steam generators or boilers. These projects burn primarily natural gas to generate the steam and emit the combustion gases to the environment containing wasted heat, wasted water vapor, carbon dioxide, nitrogen oxides, sulfur oxides and other pollutants. Additional energy and steam are wasted in the equipment used to generate and transport the steam to the reservoir. They also must generate boiler quality feed water for steam generation. This requires significant amounts of make-up water and the disposal of wasted blowdown water. Consequently, by generating steam at surface, SAGD
projects waste energy and water; emits carbon dioxides and other pollutants to the environment; and require significant amounts of capital and operating expenditures.
It can be appreciated that SEGD and SAGD relies on gravity to flow mobilized hydrocarbons to a production well located a depth greater than the injection wells. These gravity
- 4 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 assisted systems and methods are not efficient or capable of rejuvenating a partially depleted or heavy oil formation.
Therefore, a need exists for a new and improved sustainable enhanced oil recovery of heavy oil that can be used for producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation. In this regard, the present technology substantially fulfills this need. In this respect, the SEOR according to the present technology substantially departs from the conventional concepts and designs of the prior art, and in doing so provides an apparatus primarily developed for the purpose of producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation.
SUMMARY OF THE INVENTION
In view of the foregoing disadvantages inherent in the known types of CHOP, SEGD and/or SAGD systems and methods now present in the prior art, the present technology provides an improved sustainable enhanced oil recovery of heavy oil, and overcomes the above-mentioned disadvantages and drawbacks of the prior art. As such, the general purpose of the present technology, which will be described subsequently in greater detail, is to provide a new and improved sustainable enhanced oil recovery of heavy oil and method which has all the advantages of the prior art mentioned heretofore and many novel features that result in a sustainable enhanced oil recovery of heavy oil which is not anticipated, rendered obvious, suggested, or even implied by the prior art, either alone or in any combination thereof.
According to one aspect of the present technology, the present technology can include a method for recovering hydrocarbon material from a subterranean formation containing hydrocarbon material. The method can include providing a first well in the formation, and a second well in the formation vertically displaced from the first well. Injecting water into the formation from the first well. Injecting a fuel and air or oxygen into an interior of the second well.
Combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases.
Contacting the water with the combustion gas or gases in the formation to vaporize the water to create steam. Repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen. Contacting the combustion gas or gases with the hydrocarbon material in the formation to reduce the viscosity of the hydrocarbon material for mobilizing the hydrocarbon material toward the third well. Then producing the mobilized
Therefore, a need exists for a new and improved sustainable enhanced oil recovery of heavy oil that can be used for producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation. In this regard, the present technology substantially fulfills this need. In this respect, the SEOR according to the present technology substantially departs from the conventional concepts and designs of the prior art, and in doing so provides an apparatus primarily developed for the purpose of producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation.
SUMMARY OF THE INVENTION
In view of the foregoing disadvantages inherent in the known types of CHOP, SEGD and/or SAGD systems and methods now present in the prior art, the present technology provides an improved sustainable enhanced oil recovery of heavy oil, and overcomes the above-mentioned disadvantages and drawbacks of the prior art. As such, the general purpose of the present technology, which will be described subsequently in greater detail, is to provide a new and improved sustainable enhanced oil recovery of heavy oil and method which has all the advantages of the prior art mentioned heretofore and many novel features that result in a sustainable enhanced oil recovery of heavy oil which is not anticipated, rendered obvious, suggested, or even implied by the prior art, either alone or in any combination thereof.
According to one aspect of the present technology, the present technology can include a method for recovering hydrocarbon material from a subterranean formation containing hydrocarbon material. The method can include providing a first well in the formation, and a second well in the formation vertically displaced from the first well. Injecting water into the formation from the first well. Injecting a fuel and air or oxygen into an interior of the second well.
Combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases.
Contacting the water with the combustion gas or gases in the formation to vaporize the water to create steam. Repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen. Contacting the combustion gas or gases with the hydrocarbon material in the formation to reduce the viscosity of the hydrocarbon material for mobilizing the hydrocarbon material toward the third well. Then producing the mobilized
- 5 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 hydrocarbon material from a third well in the formation laterally displaced from the first and second wells.
According to another aspect, the present technology, a method for recovering heavy oil from a subterranean formation that has undergone a previous process to the subterranean formation. The method can include utilizing a first well in the formation as an injection well, and a second well in the formation vertically displaced from the first well as a combustion well.
Injecting water into the formation from the first well. Injecting a fuel and air or oxygen into an interior of the second well.
Combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases that exits the second well and travels into the formation. Creating steam in the formation by contacting the water with the combustion gas or gases to vaporize at least part of the water.
Repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen. Collapsing wormholes created by the previous process by the combustion gas or gases being introduced into the wormholes or an area surrounding the wormholes. Contacting the combustion gas or gases with the heavy oil in the formation to reduce the viscosity of the heavy oil for mobilizing the heavy oil toward the third well. Then producing the mobilized heavy oil from a third well in the formation laterally displaced from the first and second wells.
According to yet another aspect, the present technology can include a system for recovering heavy oil from a subterranean formation that has undergone a previous process to the subterranean formation. The system can include a first well configured as an injection well, a second well configured as a combustion well and vertically displaced from the first well, and a plurality of production wells laterally offset from the first and second wells. The second well is configurable to create an in situ combustion by having a slotted liner defining a plurality of bores, and including therein an igniter, a fuel tubing, and a gas tubing. The fuel tubing and the gas tubing each has at least one port configured to deliver a flow into an interior of the slotted liner. The igniter is configured to ignite the flow from the fuel tubing and the gas tubing to create the in situ combustion within the slotted liner.
In some embodiments of the present technology, the first and second wells can be horizontal wells.
In some embodiments of the present technology, the third well can be a plurality of vertical wells located around the first and second wells.
According to another aspect, the present technology, a method for recovering heavy oil from a subterranean formation that has undergone a previous process to the subterranean formation. The method can include utilizing a first well in the formation as an injection well, and a second well in the formation vertically displaced from the first well as a combustion well.
Injecting water into the formation from the first well. Injecting a fuel and air or oxygen into an interior of the second well.
Combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases that exits the second well and travels into the formation. Creating steam in the formation by contacting the water with the combustion gas or gases to vaporize at least part of the water.
Repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen. Collapsing wormholes created by the previous process by the combustion gas or gases being introduced into the wormholes or an area surrounding the wormholes. Contacting the combustion gas or gases with the heavy oil in the formation to reduce the viscosity of the heavy oil for mobilizing the heavy oil toward the third well. Then producing the mobilized heavy oil from a third well in the formation laterally displaced from the first and second wells.
According to yet another aspect, the present technology can include a system for recovering heavy oil from a subterranean formation that has undergone a previous process to the subterranean formation. The system can include a first well configured as an injection well, a second well configured as a combustion well and vertically displaced from the first well, and a plurality of production wells laterally offset from the first and second wells. The second well is configurable to create an in situ combustion by having a slotted liner defining a plurality of bores, and including therein an igniter, a fuel tubing, and a gas tubing. The fuel tubing and the gas tubing each has at least one port configured to deliver a flow into an interior of the slotted liner. The igniter is configured to ignite the flow from the fuel tubing and the gas tubing to create the in situ combustion within the slotted liner.
In some embodiments of the present technology, the first and second wells can be horizontal wells.
In some embodiments of the present technology, the third well can be a plurality of vertical wells located around the first and second wells.
- 6 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 In some embodiments of the present technology, the third well can be a plurality of horizontal wells located laterally offset from the second well.
In some embodiments of the present technology, the third well can be a plurality of horizontal wells located at a depth greater than the second well and each being laterally offset from the second well.
In some embodiments of the present technology, wherein the method is conducted after a previous process was conducted on the formation, wherein the hydrocarbon material is heavy oil.
Some embodiments of the present technology can include the step of collapsing wormholes formed during the previous process by the introduction of the combustion gas or gases into the wormholes.
Some embodiments of the present technology can include the step of collapsing the wormholes further by rapid depressuring at said third well.
In some embodiments of the present technology, the previous process is selected from the group consisting of a cold heavy oil production process, waterflooding, bottom water drive, and top gas drive.
In some embodiments of the present technology, the fuel is a hydrocarbon fuel.
In some embodiments of the present technology, the hydrocarbon fuel is natural gas.
In some embodiments of the present technology, the combustion gas or gases includes carbon dioxide.
In some embodiments of the present technology, the formation is of a thickness not suitable for a gravity drainage process.
In some embodiments of the present technology, the steam condenses to water and is produced along with the mobilize hydrocarbon material by the third well.
In some embodiments of the present technology, the water produced by the third well is recirculated for injection into the formation by way of the first well.
There has thus been outlined, rather broadly, the more important features of the invention in order that the detailed description thereof that follows may be better understood and in order that the present contribution to the art may be better appreciated.
Numerous objects, features and advantages of the present technology will be readily apparent to those of ordinary skill in the art upon a reading of the following detailed description of the invention, but nonetheless illustrative, embodiments of the present technology when taken in conjunction with the accompanying drawings. In this respect, before explaining the current
In some embodiments of the present technology, the third well can be a plurality of horizontal wells located at a depth greater than the second well and each being laterally offset from the second well.
In some embodiments of the present technology, wherein the method is conducted after a previous process was conducted on the formation, wherein the hydrocarbon material is heavy oil.
Some embodiments of the present technology can include the step of collapsing wormholes formed during the previous process by the introduction of the combustion gas or gases into the wormholes.
Some embodiments of the present technology can include the step of collapsing the wormholes further by rapid depressuring at said third well.
In some embodiments of the present technology, the previous process is selected from the group consisting of a cold heavy oil production process, waterflooding, bottom water drive, and top gas drive.
In some embodiments of the present technology, the fuel is a hydrocarbon fuel.
In some embodiments of the present technology, the hydrocarbon fuel is natural gas.
In some embodiments of the present technology, the combustion gas or gases includes carbon dioxide.
In some embodiments of the present technology, the formation is of a thickness not suitable for a gravity drainage process.
In some embodiments of the present technology, the steam condenses to water and is produced along with the mobilize hydrocarbon material by the third well.
In some embodiments of the present technology, the water produced by the third well is recirculated for injection into the formation by way of the first well.
There has thus been outlined, rather broadly, the more important features of the invention in order that the detailed description thereof that follows may be better understood and in order that the present contribution to the art may be better appreciated.
Numerous objects, features and advantages of the present technology will be readily apparent to those of ordinary skill in the art upon a reading of the following detailed description of the invention, but nonetheless illustrative, embodiments of the present technology when taken in conjunction with the accompanying drawings. In this respect, before explaining the current
- 7 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 embodiment of the invention in detail, it is to be understood that the invention is not limited in its application to the details of construction and to the arrangements of the components set forth in the following description or illustrated in the drawings. The invention is capable of other embodiments and of being practiced and carried out in various ways. Also, it is to be understood that the phraseology and terminology employed herein are for the purpose of descriptions and should not be regarded as limiting.
It is therefore an object of the present technology to provide a new and improved sustainable enhanced oil recovery of heavy oil that has all of the advantages of the prior art CHOP, SEGD
and/or SAGD systems and methods and none of the disadvantages.
For a better understanding of the invention, its operating advantages and the specific objects attained by its uses, reference should be had to the accompanying drawings and descriptive matter in which there are illustrated embodiments of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
The invention will be better understood and objects other than those set forth above will become apparent when consideration is given to the following detailed description thereof. Such description makes reference to the annexed drawings wherein:
FIGS 1 and 2 are a schematic side views of the SEGD known in the prior art.
FIG. 3 is a cross-sectional view of the combined steam injection and combustion well of the known SEGD system.
FIG. 4 is a cross-sectional view of the combined steam injection and combustion well of the known SEGD taken along line 4-4 in Fig. 3.
FIG. 5 is a schematic front view of the SEOR system and method constructed in accordance with the principles of the present technology, with the phantom lines depicting environmental structure.
FIG. 6 is a schematic side view of the SEOR system and method of the present technology.
FIG. 7 is a schematic front view of the SEOR system and method illustrating a plurality of vertical production wells and collapsed wormholes.
FIG. 8 is a schematic top view of the plurality of vertical and/or horizontal production wells utilized in the SEOR system and method.
FIG. 9 is a schematic diagram of above ground systems utilizable with the SEOR
system and method of the present technology.
It is therefore an object of the present technology to provide a new and improved sustainable enhanced oil recovery of heavy oil that has all of the advantages of the prior art CHOP, SEGD
and/or SAGD systems and methods and none of the disadvantages.
For a better understanding of the invention, its operating advantages and the specific objects attained by its uses, reference should be had to the accompanying drawings and descriptive matter in which there are illustrated embodiments of the invention.
BRIEF DESCRIPTION OF THE DRAWINGS
The invention will be better understood and objects other than those set forth above will become apparent when consideration is given to the following detailed description thereof. Such description makes reference to the annexed drawings wherein:
FIGS 1 and 2 are a schematic side views of the SEGD known in the prior art.
FIG. 3 is a cross-sectional view of the combined steam injection and combustion well of the known SEGD system.
FIG. 4 is a cross-sectional view of the combined steam injection and combustion well of the known SEGD taken along line 4-4 in Fig. 3.
FIG. 5 is a schematic front view of the SEOR system and method constructed in accordance with the principles of the present technology, with the phantom lines depicting environmental structure.
FIG. 6 is a schematic side view of the SEOR system and method of the present technology.
FIG. 7 is a schematic front view of the SEOR system and method illustrating a plurality of vertical production wells and collapsed wormholes.
FIG. 8 is a schematic top view of the plurality of vertical and/or horizontal production wells utilized in the SEOR system and method.
FIG. 9 is a schematic diagram of above ground systems utilizable with the SEOR
system and method of the present technology.
- 8 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 FIG. 10 is a graph showing the viscosity of Lloydminster heavy oil and the CO2 saturage of heavy oil feed #1.
The same reference numerals refer to the same parts throughout the various figures.
DETAILED DESCRIPTION OF THE INVENTION
In FIGS. 1 and 2, the SEGD system and method is initially utilized for producing hydrocarbons from a formation using in situ steam generation and gravity drainage. More particularly, the SEGD system and method is used in removing, extracting or producing hydrocarbon material, such as but not limited to bitumen, from a subterranean formation or reservoir 2 that can include an overlying zone 4, such as but not limited to a gas zone, water zone or cap rock zone. The SEGD system and method includes a multi-configurable production well 12, amulti-configurable water injection well 18 located vertically above the production well 12 and near the overlying zone 4, and a multi-configurable combined steam injection and in situ combustion well 20 located between the production well 12 and water injection well 18.
Alternatively, the production well 12 can also be used as a steam injection well, and the water injection well 18 can also be a carbon dioxide (CO2) or combustion gas production well. The production well 12, the water injection well 18, and the combined well 20, each can include tubing strings, downhole systems and assemblies, and/or any means to contribute to their intended purpose.
It can be appreciated that the production well 12, water injection well 18 and combined well 20 can be vertical and/or substantially vertical wells, horizontal or substantially horizontal wells, J-shaped wells, L-shaped wells, U-shaped wells, and/or any combination thereof.
For exemplarily purposes regarding the present application, the production well 12, water injection well 18 and combined well 20 are horizontal wells approximately vertically aligned and vertically displaced. It can be appreciated that the known SEGD system and method locate the three wells in vertically displaced alignment, therefor allowing gravity to drain the mobilized oil down to the production well 12.
The SEGD system and method initiates a SAGD process by circulating and/or injecting steam into the reservoir 2 through the combined well 20 and/or the production well 12 until a steam chamber 22 eventually develops to the top of the reservoir 2, and a production boundary 14 is created adjacent the steam chamber 22, as best illustrated in FIGS. 1 and 2.
It can be appreciated that the steam 24 can be circulated in the production well 12 alone or in combination with the
The same reference numerals refer to the same parts throughout the various figures.
DETAILED DESCRIPTION OF THE INVENTION
In FIGS. 1 and 2, the SEGD system and method is initially utilized for producing hydrocarbons from a formation using in situ steam generation and gravity drainage. More particularly, the SEGD system and method is used in removing, extracting or producing hydrocarbon material, such as but not limited to bitumen, from a subterranean formation or reservoir 2 that can include an overlying zone 4, such as but not limited to a gas zone, water zone or cap rock zone. The SEGD system and method includes a multi-configurable production well 12, amulti-configurable water injection well 18 located vertically above the production well 12 and near the overlying zone 4, and a multi-configurable combined steam injection and in situ combustion well 20 located between the production well 12 and water injection well 18.
Alternatively, the production well 12 can also be used as a steam injection well, and the water injection well 18 can also be a carbon dioxide (CO2) or combustion gas production well. The production well 12, the water injection well 18, and the combined well 20, each can include tubing strings, downhole systems and assemblies, and/or any means to contribute to their intended purpose.
It can be appreciated that the production well 12, water injection well 18 and combined well 20 can be vertical and/or substantially vertical wells, horizontal or substantially horizontal wells, J-shaped wells, L-shaped wells, U-shaped wells, and/or any combination thereof.
For exemplarily purposes regarding the present application, the production well 12, water injection well 18 and combined well 20 are horizontal wells approximately vertically aligned and vertically displaced. It can be appreciated that the known SEGD system and method locate the three wells in vertically displaced alignment, therefor allowing gravity to drain the mobilized oil down to the production well 12.
The SEGD system and method initiates a SAGD process by circulating and/or injecting steam into the reservoir 2 through the combined well 20 and/or the production well 12 until a steam chamber 22 eventually develops to the top of the reservoir 2, and a production boundary 14 is created adjacent the steam chamber 22, as best illustrated in FIGS. 1 and 2.
It can be appreciated that the steam 24 can be circulated in the production well 12 alone or in combination with the
- 9 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 combined well 20, for a predetermined time period, for example 2-3 months.
Thus heating the hydrocarbon material or bitumen between both the production and combined wells.
After the predetermined time period has lapsed, any steam injection through production well 12 is stopped, and the production well 12 is recompleted. The long string LS
of the production well 12 may be removed and a lifting mechanism (not shown), such as but not limited to, a downhole pump or gas lifting means, is placed downhole. Continuous steam injection can be applied into the surrounding reservoir 2, and thus consequently growing the steam chamber 22.
Hot hydrocarbon fluids or bitumen emulsion 16 and steam condensate at the boundary 14 of the steam chamber 22 flows downward and towards the recompleted production well 12. The hot hydrocarbon fluids 16 are produced through the production well 12 and lifted to the surface via the lifting mechanism, while steam injection is continued through the combined well 20. This SAGD
process continues until the steam chamber 22 reaches the top of the reservoir 2 and/or until it reaches the overlying zone 4, then all steam injection can be stopped.
After the SAGD process is finished, the combined well 20 can be recompleted and converted to an in situ SEGD combustion well 20. Water 26 is injected into the top portion of the reservoir 2 through water injection well 18, and allowed to fall toward the combustion well 20 via gravity, as best illustrated in FIG. 1.
In reference to FIG. 2, when the water front 26 approaches the combustion well 20, the SEGD process is initiated. Combustion gases are injected into the combustion well 20 to create an in situ combustion 28 configured for hydrocarbon production and to vaporize the injected water 26.
When the water 26 contacts and mixes with the in situ combusted gases 28, the water 26 is vaporized and converted to steam 29 which rises to the top of the reservoir 2 to create a water, steam and CO2 envelope. The steam 29 heats and reduces the viscosity of the surrounding hydrocarbon material 16. After a predetermined amount of time, the treated hydrocarbon material 16, and possible other fluids such as steam condensate, are mobilized and drain toward the production well 12, and are produced and lifted to the surface for further processing.
The resulting CO2 can be sequestered into the gas or water zone 4 in the case that the overlying zone 4 is a gas or water zone. In the case the overlying zone 4 is a cap rock zone, CO2 will migrate into the reservoir 2 where it can be sequestered or be produced by adjacent wells 18.
The SEGD system and method can utilized a combined steam injection and in situ combustion well 20, as best illustrated in FIGS. 3 and 4, includes a primary casing 30, a slotted liner 32 including a hanger, a flexible fuel tubing 36, a flexible air, oxygen or gas tubing 40, an igniter
Thus heating the hydrocarbon material or bitumen between both the production and combined wells.
After the predetermined time period has lapsed, any steam injection through production well 12 is stopped, and the production well 12 is recompleted. The long string LS
of the production well 12 may be removed and a lifting mechanism (not shown), such as but not limited to, a downhole pump or gas lifting means, is placed downhole. Continuous steam injection can be applied into the surrounding reservoir 2, and thus consequently growing the steam chamber 22.
Hot hydrocarbon fluids or bitumen emulsion 16 and steam condensate at the boundary 14 of the steam chamber 22 flows downward and towards the recompleted production well 12. The hot hydrocarbon fluids 16 are produced through the production well 12 and lifted to the surface via the lifting mechanism, while steam injection is continued through the combined well 20. This SAGD
process continues until the steam chamber 22 reaches the top of the reservoir 2 and/or until it reaches the overlying zone 4, then all steam injection can be stopped.
After the SAGD process is finished, the combined well 20 can be recompleted and converted to an in situ SEGD combustion well 20. Water 26 is injected into the top portion of the reservoir 2 through water injection well 18, and allowed to fall toward the combustion well 20 via gravity, as best illustrated in FIG. 1.
In reference to FIG. 2, when the water front 26 approaches the combustion well 20, the SEGD process is initiated. Combustion gases are injected into the combustion well 20 to create an in situ combustion 28 configured for hydrocarbon production and to vaporize the injected water 26.
When the water 26 contacts and mixes with the in situ combusted gases 28, the water 26 is vaporized and converted to steam 29 which rises to the top of the reservoir 2 to create a water, steam and CO2 envelope. The steam 29 heats and reduces the viscosity of the surrounding hydrocarbon material 16. After a predetermined amount of time, the treated hydrocarbon material 16, and possible other fluids such as steam condensate, are mobilized and drain toward the production well 12, and are produced and lifted to the surface for further processing.
The resulting CO2 can be sequestered into the gas or water zone 4 in the case that the overlying zone 4 is a gas or water zone. In the case the overlying zone 4 is a cap rock zone, CO2 will migrate into the reservoir 2 where it can be sequestered or be produced by adjacent wells 18.
The SEGD system and method can utilized a combined steam injection and in situ combustion well 20, as best illustrated in FIGS. 3 and 4, includes a primary casing 30, a slotted liner 32 including a hanger, a flexible fuel tubing 36, a flexible air, oxygen or gas tubing 40, an igniter
- 10 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 44, and a combustor assembly packer 34. The combustor assembly packer 34 is configured to seal an area of the interior of the slotted liner 32 adjacent or upstream of the igniter 44, so that no combustion gases escape up the slotted liner 32 and/or into the combined well 20. The gas tubing 40 can be configured to deliver oxygen, air or any gas suitable for combustion in combination with a fuel delivered by the fuel tubing 36.
The slotted liner 32 features a plurality of radially defined bores 33 for the injection of steam during the SAGD process, and for exhausting combustion gases resulting from the in situ combustion into the surrounding reservoir 2 during the SEGD process. It can be appreciated that any number and configurations of the bores 33 can be used with the slotted liner 32. Furthermore, it __ can be appreciated that additional peripheral systems or devices, such as but not limited to, valves, sleeves, jets, plugs, and degradable or erodible materials can be associated with the bores 33.
The fuel tubing 36 features a plurality of fuel ports 38, and the gas tubing 40 features a plurality of gas ports 42. The fuel tubing 36 and gas tubing 40 may be located adjacent to each other with the fuel and gas ports 38, 42 angled toward each other so that their flows converge. It can further be appreciated that the fuel ports 38 and gas ports 42 can be a plurality of ports radially defined in the fuel tubing 36 and gas tubing 40, respectively, or can be oriented in any direction that allows their flows to contact and mix within the slotted liner 32. It can be appreciated that the fuel tubing 36 and gas tubing 40 can be welded together along a longitudinal axis, thereby creating a paired fuel and gas tubing. Still further, it can be appreciated that the fuel tubing 36 and gas tubing 40 may be located anywhere in the slotted liner 32 so as to allow the flows from the fuel and gas ports 38, 42 to contact and mix within the slotted liner 32.
The igniter 44 is located adjacent a heel of the combined well 20 and adjacent a point of convergence of the fuel and gas flows. The location of the igniter 44 provides ideal ignition of the fuel and gas flows to produce combustion or flame 46 within the slotted liner 32.
Alternate embodiment nozzles associated with the fuel tubing 36 and gas tubing 40 can be utilized, such as but not limited to, a substantially inverted V-shaped nozzle configuration, a substantially inverted Y-shaped nozzle configuration or a substantially L-shaped nozzle configuration. It can be appreciated that the nozzles can be a single nozzle unit associated with each fuel port and gas port pairing, or can be designed as a manifold, which has a single main body featuring multiple exit ports, and/or multiple fuel and gas cylinders extending toward their corresponding fuel and gas ports. Optionally, the nozzle or nozzles can include exit sleeves having a substantially oval shape and configured to receive exit sections of the fuel and gas cylinders
The slotted liner 32 features a plurality of radially defined bores 33 for the injection of steam during the SAGD process, and for exhausting combustion gases resulting from the in situ combustion into the surrounding reservoir 2 during the SEGD process. It can be appreciated that any number and configurations of the bores 33 can be used with the slotted liner 32. Furthermore, it __ can be appreciated that additional peripheral systems or devices, such as but not limited to, valves, sleeves, jets, plugs, and degradable or erodible materials can be associated with the bores 33.
The fuel tubing 36 features a plurality of fuel ports 38, and the gas tubing 40 features a plurality of gas ports 42. The fuel tubing 36 and gas tubing 40 may be located adjacent to each other with the fuel and gas ports 38, 42 angled toward each other so that their flows converge. It can further be appreciated that the fuel ports 38 and gas ports 42 can be a plurality of ports radially defined in the fuel tubing 36 and gas tubing 40, respectively, or can be oriented in any direction that allows their flows to contact and mix within the slotted liner 32. It can be appreciated that the fuel tubing 36 and gas tubing 40 can be welded together along a longitudinal axis, thereby creating a paired fuel and gas tubing. Still further, it can be appreciated that the fuel tubing 36 and gas tubing 40 may be located anywhere in the slotted liner 32 so as to allow the flows from the fuel and gas ports 38, 42 to contact and mix within the slotted liner 32.
The igniter 44 is located adjacent a heel of the combined well 20 and adjacent a point of convergence of the fuel and gas flows. The location of the igniter 44 provides ideal ignition of the fuel and gas flows to produce combustion or flame 46 within the slotted liner 32.
Alternate embodiment nozzles associated with the fuel tubing 36 and gas tubing 40 can be utilized, such as but not limited to, a substantially inverted V-shaped nozzle configuration, a substantially inverted Y-shaped nozzle configuration or a substantially L-shaped nozzle configuration. It can be appreciated that the nozzles can be a single nozzle unit associated with each fuel port and gas port pairing, or can be designed as a manifold, which has a single main body featuring multiple exit ports, and/or multiple fuel and gas cylinders extending toward their corresponding fuel and gas ports. Optionally, the nozzle or nozzles can include exit sleeves having a substantially oval shape and configured to receive exit sections of the fuel and gas cylinders
- 11 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 therein and to combine or mix the fuel and gas flows to produce a horizontally or substantially horizontally extending flame.
With respect to the above described SEGD process, after the production well
With respect to the above described SEGD process, after the production well
12, the water injection well 18, and the combined well 20 have been drilled or formed; the following exemplary SEGD process or method can be implemented.
A steam chamber 22 is created from the combined well 20 to the top of reservoir 2.
Produced water 26 can be filtered and injected into the top portion of reservoir 2 through the water injection well 18 at a temperature at or lower than the steam chamber temperature. The water 26 drains downward toward the combined well 20 by way of gravity.
Natural gas in combination with oxygen or air are injected into the combined well 20 through fuel tubing 36 and gas tubing 40 respectively. Combustion of the natural gas and oxygen or air ensues downhole inside the slotted liner 32 via the igniter 44, thereby converting the combined well 20 into a burner.
Consequently, combustion gases 28 (steam and CO2) flow into the reservoir 2 and rise upwardly due to the buoyancy toward the draining water 26. The draining water 26 vaporizes into steam 29 when it contacts and mixes with the combustion gases produced by the combined well 20.
The combined combustion gases 28 and steam 29 flow upwards and sideways toward the sides of the chamber 22 converting the initial steam chamber into a combined steam and combustion gas chamber (steam/gas chamber 22). The hydrocarbon material or bitumen at the sides of the chamber 22 is heated by the steam/gas chamber 22 causing the steam to condense and some CO2 to dissolve into the heated bitumen.
The heated bitumen including some dissolved CO2 is mobilized toward the production well 12, and then lifted to the surface for processing. Additionally, the connate water and the steam condensate are drained to the production well 12 by way of gravity, and are lifted to the surface for processing.
The SEGD method was utilized in combination with new formation production, and not for rejuvenating previously processed formations that have undergone CHOP, waterflooding, bottom water drive, or top gas drive. While, the SEOR present technology provides substantial benefits and unexpected results when used for rejuvenating for example CHOP wells by employing different productions wells. It was not known to one skilled in the art to utilize SEGD
to recover heavy oil from a CHOP, waterflooded, bottom water driven, or top gas driven formations.
Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Referring now to the drawings, and particularly to FIGS. 5-9, embodiments of the SEOR
system and method of the present technology is shown and will be described. In the exemplary, the SEOR system and method of the present technology can be utilized in a formation that has previously gone through a heavy oil extraction process, such as but not limited to, CHOP, waterflooding, bottom water drive, or top gas drive.
In the exemplary, as illustrated in FIGS. 5 and 6, previously used vertical or horizontal wells PW in the CHOP process create and leave behind wormholes or conduit network WH
as a result of the sand production creates. Gas saturation increases to replace the produced oil, connate water and sand. Eventually, the reservoir pressure declines to a low pressure such that the wells are no longer productive.
The present technology can take advantage of these wormholes by collapsing them to create permeable channels to more efficiently mobiles heavy oil toward production wells. The present technology can also be utilized in reservoirs having a payzone thickness or depth not suitable for SEGD or SAGD operations. This is in part because the present technology utilizes a mobile pressure front created by in situ combustion resulting in the in situ creation of steam and CO2 without the need of a drainage production well that requires the reservoir payzone to have a substantial thickness or depth.
The SEOR system and method of the present technology can be utilized to rejuvenate and/or repressurize a non-productive or a limited-productive reservoir 2 resulting from a previously extraction process, such as but not limited to CHOP, waterflooding, bottom water drive, or top gas drive. The reservoir 2 may be below an overlying zone 4, such as but not limited to a gas zone, water zone or cap rock zone, and may be above an underlying zone 3.
Furthermore, the reservoir 2 may be a single or a series of thin oil payzones. Still further, the reservoir 2 may be a new formation that has not undergone any previous extraction process.
In view of the foregoing non-thermal production methods and the current states of the reservoirs, the present technology provides an enhanced oil recovery method and process that can profitably increase the production and reserves from these reservoirs. This invention mobilizes heavy oil using various mechanisms such as collapsing the wormholes CWH, repressurizing the reservoirs with carbon dioxide gas saturation, dissolving CO2 into the oil and swelling it, reducing the viscosity of the oil thermally and with CO2, and further displacing oil with CO2 and steam or hot water. The SEOR method can utilize the water injection well 18 and the combustion well 20 of the SEGD system, but replaces the vertically aligned and displaced production well of SEGD with a
A steam chamber 22 is created from the combined well 20 to the top of reservoir 2.
Produced water 26 can be filtered and injected into the top portion of reservoir 2 through the water injection well 18 at a temperature at or lower than the steam chamber temperature. The water 26 drains downward toward the combined well 20 by way of gravity.
Natural gas in combination with oxygen or air are injected into the combined well 20 through fuel tubing 36 and gas tubing 40 respectively. Combustion of the natural gas and oxygen or air ensues downhole inside the slotted liner 32 via the igniter 44, thereby converting the combined well 20 into a burner.
Consequently, combustion gases 28 (steam and CO2) flow into the reservoir 2 and rise upwardly due to the buoyancy toward the draining water 26. The draining water 26 vaporizes into steam 29 when it contacts and mixes with the combustion gases produced by the combined well 20.
The combined combustion gases 28 and steam 29 flow upwards and sideways toward the sides of the chamber 22 converting the initial steam chamber into a combined steam and combustion gas chamber (steam/gas chamber 22). The hydrocarbon material or bitumen at the sides of the chamber 22 is heated by the steam/gas chamber 22 causing the steam to condense and some CO2 to dissolve into the heated bitumen.
The heated bitumen including some dissolved CO2 is mobilized toward the production well 12, and then lifted to the surface for processing. Additionally, the connate water and the steam condensate are drained to the production well 12 by way of gravity, and are lifted to the surface for processing.
The SEGD method was utilized in combination with new formation production, and not for rejuvenating previously processed formations that have undergone CHOP, waterflooding, bottom water drive, or top gas drive. While, the SEOR present technology provides substantial benefits and unexpected results when used for rejuvenating for example CHOP wells by employing different productions wells. It was not known to one skilled in the art to utilize SEGD
to recover heavy oil from a CHOP, waterflooded, bottom water driven, or top gas driven formations.
Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Referring now to the drawings, and particularly to FIGS. 5-9, embodiments of the SEOR
system and method of the present technology is shown and will be described. In the exemplary, the SEOR system and method of the present technology can be utilized in a formation that has previously gone through a heavy oil extraction process, such as but not limited to, CHOP, waterflooding, bottom water drive, or top gas drive.
In the exemplary, as illustrated in FIGS. 5 and 6, previously used vertical or horizontal wells PW in the CHOP process create and leave behind wormholes or conduit network WH
as a result of the sand production creates. Gas saturation increases to replace the produced oil, connate water and sand. Eventually, the reservoir pressure declines to a low pressure such that the wells are no longer productive.
The present technology can take advantage of these wormholes by collapsing them to create permeable channels to more efficiently mobiles heavy oil toward production wells. The present technology can also be utilized in reservoirs having a payzone thickness or depth not suitable for SEGD or SAGD operations. This is in part because the present technology utilizes a mobile pressure front created by in situ combustion resulting in the in situ creation of steam and CO2 without the need of a drainage production well that requires the reservoir payzone to have a substantial thickness or depth.
The SEOR system and method of the present technology can be utilized to rejuvenate and/or repressurize a non-productive or a limited-productive reservoir 2 resulting from a previously extraction process, such as but not limited to CHOP, waterflooding, bottom water drive, or top gas drive. The reservoir 2 may be below an overlying zone 4, such as but not limited to a gas zone, water zone or cap rock zone, and may be above an underlying zone 3.
Furthermore, the reservoir 2 may be a single or a series of thin oil payzones. Still further, the reservoir 2 may be a new formation that has not undergone any previous extraction process.
In view of the foregoing non-thermal production methods and the current states of the reservoirs, the present technology provides an enhanced oil recovery method and process that can profitably increase the production and reserves from these reservoirs. This invention mobilizes heavy oil using various mechanisms such as collapsing the wormholes CWH, repressurizing the reservoirs with carbon dioxide gas saturation, dissolving CO2 into the oil and swelling it, reducing the viscosity of the oil thermally and with CO2, and further displacing oil with CO2 and steam or hot water. The SEOR method can utilize the water injection well 18 and the combustion well 20 of the SEGD system, but replaces the vertically aligned and displaced production well of SEGD with a
- 13 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 plurality of vertical production wells 12' that are located around the injection and combustion wells 18, 20, as best illustrated in FIG. 8. It can be appreciated the production wells 12' can be horizontal wells located laterally offset from the combustion well 20. As discussed above, the combustion well 20 can be a combined well configured as a production or combustion well.
If the overlying zone 4 is a cap rock, then the CO2 may be retained thereunder to maintain or increase pressure within the reservoir 2 or for production from an additional production well located in an area between the reservoir 2 and overlying zone 4. In an alternative, if the overlying zone 4 is for example sand, the CO2 may flow therein for sequestration.
To attain this, the present technology can include injecting water 26 into reservoir 2 from the top horizontal well 18. The water 26 drains down toward the combustion well 20 to create a liquid water inner core WC. A hydrocarbon fuel is mixed with oxygen or air and combusted inside a liner 32 of the bottom horizontal well 20. The hydrocarbon fuel can be, but is not limited to, natural gas, fuel oil, heavy oil, bitumen, residuum, emulsified fuel, multiphase superfine atomized residue, asphaltenes, petcoke, coal and combinations thereof. The resulting combustion gases 28 contact the flowing water 26 to create a steam and combustion gases 28 that penetrate, permeate and travel into the reservoir 2. The combustion gases 28 vaporizes most of the injected water 26 to steam by heat transfer mechanisms of conduction, convection and fluid mixing to create a steam and CO2 gas chamber SGC. The combined steam and CO2 SC flows laterally away from injection well 18 and combustion well 20. The steam will heat the adjacent formation 2 and oil, and will condense to hot water HW. The CO2 CO will permeate ahead pressurizing the reservoir 2 and dissolve into the oil, swelling it and reducing its viscosity thereby allowing the oil to flow OF by the moving CO2 CO
pressure front toward the production wells 12'. The CO2 will contact the reservoir oil through existing wormholes WH and through the continuous gas saturation or phase. Some of the wormholes WH will collapse CWH due to oil viscosity being reduced significantly by CO2, as best illustrated in FIG. 7. Consequently, the wormholes can be collapsed by the introduction of the resultant CO2, the resultant steam and/or by a rapid depressurization at the production wells.
It can be appreciated that the water inner core WC can develop into a pyramid-like configuration first and then to an oval configuration until it contacts the combustion front from the combustion well 20. Surrounding the water inner core WC can be a steam, combustion gas and water chamber SGWC mixture. This mixture chamber SGWC can propagate and permeate vertically and laterally from the combustion well 20 and into the surrounding formation, thereby mobilizing the heavy oil. It can further be appreciated that the mixture chamber SGWC may
If the overlying zone 4 is a cap rock, then the CO2 may be retained thereunder to maintain or increase pressure within the reservoir 2 or for production from an additional production well located in an area between the reservoir 2 and overlying zone 4. In an alternative, if the overlying zone 4 is for example sand, the CO2 may flow therein for sequestration.
To attain this, the present technology can include injecting water 26 into reservoir 2 from the top horizontal well 18. The water 26 drains down toward the combustion well 20 to create a liquid water inner core WC. A hydrocarbon fuel is mixed with oxygen or air and combusted inside a liner 32 of the bottom horizontal well 20. The hydrocarbon fuel can be, but is not limited to, natural gas, fuel oil, heavy oil, bitumen, residuum, emulsified fuel, multiphase superfine atomized residue, asphaltenes, petcoke, coal and combinations thereof. The resulting combustion gases 28 contact the flowing water 26 to create a steam and combustion gases 28 that penetrate, permeate and travel into the reservoir 2. The combustion gases 28 vaporizes most of the injected water 26 to steam by heat transfer mechanisms of conduction, convection and fluid mixing to create a steam and CO2 gas chamber SGC. The combined steam and CO2 SC flows laterally away from injection well 18 and combustion well 20. The steam will heat the adjacent formation 2 and oil, and will condense to hot water HW. The CO2 CO will permeate ahead pressurizing the reservoir 2 and dissolve into the oil, swelling it and reducing its viscosity thereby allowing the oil to flow OF by the moving CO2 CO
pressure front toward the production wells 12'. The CO2 will contact the reservoir oil through existing wormholes WH and through the continuous gas saturation or phase. Some of the wormholes WH will collapse CWH due to oil viscosity being reduced significantly by CO2, as best illustrated in FIG. 7. Consequently, the wormholes can be collapsed by the introduction of the resultant CO2, the resultant steam and/or by a rapid depressurization at the production wells.
It can be appreciated that the water inner core WC can develop into a pyramid-like configuration first and then to an oval configuration until it contacts the combustion front from the combustion well 20. Surrounding the water inner core WC can be a steam, combustion gas and water chamber SGWC mixture. This mixture chamber SGWC can propagate and permeate vertically and laterally from the combustion well 20 and into the surrounding formation, thereby mobilizing the heavy oil. It can further be appreciated that the mixture chamber SGWC may
- 14 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 angularly expand from the combustion well 20 and then taper off into a more substantial horizontal flow. This can create a thickness or depth of the mixture chamber SGWC being greatest adjacent or near the combustion well 20, and decreasing the farther laterally away from the combustion well.
This mixture chamber SGWC front can move laterally depending on the formation characteristics, distance between the injection well 18 and combustion well 20, the amount of water injected from the injection well 18, the type and amount of fuel and/or air and/or oxygen injected into the combustion well 20, the length of time of injection of water, fuel and/or air or oxygen, the starting and/or length of time of production utilizing the production wells 12', PW, and the number and/or location of the production wells 12', PW.
Still further, the control of production can be used to regulate the pressure created by the in situ combustion. Even further, additional CO2 can be injected into the reservoir 2 to assist in repressurizing or increase the pressure. This additional CO2 can be injected utilizing a separate injection well (not shown) or the water injection well 18, and the additional CO2 can be supplied from a previous CO2 recovery process.
After the reservoir pressure have increased significantly and close to the original reservoir pressure, further collapsing of the wormholes CWH can occur by suddenly reducing the pressures at nearby production wells 12'. It can be appreciated that the production wells 12' can be located through or near the wormholes WH. If needed the production wells 12' can be temporarily equipped with sand screens to prevent sand production. The collapsed wormholes CWH remain as useful high permeability conduits in the reservoir 2.
After the wormholes CWH are collapsed, the production wells 12' can be further put on production to produce the mobilized oil OF, the hot water HW, the CO2 gas CO
and any other usable resource. Referring to FIG. 9, at the surface the wells 12', 18, 20 may be associated with wellhead equipment 50. The produced oil can be separated utilizing know separation techniques and systems 52 and the transferred 54 to be stored, further processes and/or sold. The produced hot water from the separator 52 can be filtered or processed 56 and/or stored 60, and reinjected into top water injection wells 18. It can be appreciated that new water can be used from other sources 62.
Combustible gases, such as natural gas, or liquids can be separated from the produced material utilizing separator 52 and recirculated 58 to fuel storage 66 for injection into the combustion well 20. New fuel or hydrocarbon fuel 66 and oxygen or air 64 can be continued to be combusted in the combustion wells 20 to vaporize the injected water to steam.
This mixture chamber SGWC front can move laterally depending on the formation characteristics, distance between the injection well 18 and combustion well 20, the amount of water injected from the injection well 18, the type and amount of fuel and/or air and/or oxygen injected into the combustion well 20, the length of time of injection of water, fuel and/or air or oxygen, the starting and/or length of time of production utilizing the production wells 12', PW, and the number and/or location of the production wells 12', PW.
Still further, the control of production can be used to regulate the pressure created by the in situ combustion. Even further, additional CO2 can be injected into the reservoir 2 to assist in repressurizing or increase the pressure. This additional CO2 can be injected utilizing a separate injection well (not shown) or the water injection well 18, and the additional CO2 can be supplied from a previous CO2 recovery process.
After the reservoir pressure have increased significantly and close to the original reservoir pressure, further collapsing of the wormholes CWH can occur by suddenly reducing the pressures at nearby production wells 12'. It can be appreciated that the production wells 12' can be located through or near the wormholes WH. If needed the production wells 12' can be temporarily equipped with sand screens to prevent sand production. The collapsed wormholes CWH remain as useful high permeability conduits in the reservoir 2.
After the wormholes CWH are collapsed, the production wells 12' can be further put on production to produce the mobilized oil OF, the hot water HW, the CO2 gas CO
and any other usable resource. Referring to FIG. 9, at the surface the wells 12', 18, 20 may be associated with wellhead equipment 50. The produced oil can be separated utilizing know separation techniques and systems 52 and the transferred 54 to be stored, further processes and/or sold. The produced hot water from the separator 52 can be filtered or processed 56 and/or stored 60, and reinjected into top water injection wells 18. It can be appreciated that new water can be used from other sources 62.
Combustible gases, such as natural gas, or liquids can be separated from the produced material utilizing separator 52 and recirculated 58 to fuel storage 66 for injection into the combustion well 20. New fuel or hydrocarbon fuel 66 and oxygen or air 64 can be continued to be combusted in the combustion wells 20 to vaporize the injected water to steam.
- 15 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Any produced CO2 can be separated 52 and used for CO2 flooding or water and CO2 gas (WAG) flooding of nearby heavy oil wells. Alternatively, any produced CO2 can be injected back into the reservoir 2 to further increase the pressure or for sequestration.
In use, it can now be understood that after CHOP or Cold Heavy Oil Production has occurred using horizontal wells, the SEOR method of the present technology can be utilized to rejuvenate and repressurize a fully or partially depleted CHOP well, to produce and recover further heavy oil from the formation.
After CHOP, two to three SEGD horizontal wells can be drilled in selected locations between or adjacent the existing wells PW utilized in the CHOP process. If needed and optional, water can be injected into the upper well 18 and oil can be produced from the lower combustion well 20, or water can be injected into the lower combustion well 20 and oil produced from the upper well 18. The upper well 18 may be recompleted to a water injection well, and the lower production well can be recompleted to a combustion well 20.
If needed, water may be blown out of the lower well 20 prior to recompleting to the combustion well or prior to combustion.
Water 26 is injected into the upper zone of the formation 2 utilizing the upper horizontal injection well 18. Natural gas and oxygen is injected and combusted in the combustion well 20 to create combustion gas 28 that moves outwardly therefrom. The water 26 gravity drains toward the combustion well 20 to contact, mix and heat transfer with the combustion gas 28 vaporizing the water to steam SC.
The steam SC heats the oil OF and condenses to water HW. Steam SC, hot water HW and CO2 CO gases migrate outwards in the reservoir 2, increasing reservoir pressure, and pushing and displacing reservoir oil and natural gas towards the nearby production wells 12'. The combustion CO2 migrates more into the reservoir 2 through the wormholes WH and gas phase, cools, becomes a solvent into the oil, and repressurizes the reservoir.
The heated heavy oil or bitumen including some dissolved CO2, the connate water and the steam condensate are mobilized toward the production wells 12', and then lifted to the surface for processing.
In the case where the reservoir 2 is entirely a bitumen reservoir; the CO2 can be produced from the top of the reservoir to maintain a predetermined and/or approved safe steam chamber pressure. The produced CO2 can be conditioned for sequestration, possibly dehydration and liquefaction.
In use, it can now be understood that after CHOP or Cold Heavy Oil Production has occurred using horizontal wells, the SEOR method of the present technology can be utilized to rejuvenate and repressurize a fully or partially depleted CHOP well, to produce and recover further heavy oil from the formation.
After CHOP, two to three SEGD horizontal wells can be drilled in selected locations between or adjacent the existing wells PW utilized in the CHOP process. If needed and optional, water can be injected into the upper well 18 and oil can be produced from the lower combustion well 20, or water can be injected into the lower combustion well 20 and oil produced from the upper well 18. The upper well 18 may be recompleted to a water injection well, and the lower production well can be recompleted to a combustion well 20.
If needed, water may be blown out of the lower well 20 prior to recompleting to the combustion well or prior to combustion.
Water 26 is injected into the upper zone of the formation 2 utilizing the upper horizontal injection well 18. Natural gas and oxygen is injected and combusted in the combustion well 20 to create combustion gas 28 that moves outwardly therefrom. The water 26 gravity drains toward the combustion well 20 to contact, mix and heat transfer with the combustion gas 28 vaporizing the water to steam SC.
The steam SC heats the oil OF and condenses to water HW. Steam SC, hot water HW and CO2 CO gases migrate outwards in the reservoir 2, increasing reservoir pressure, and pushing and displacing reservoir oil and natural gas towards the nearby production wells 12'. The combustion CO2 migrates more into the reservoir 2 through the wormholes WH and gas phase, cools, becomes a solvent into the oil, and repressurizes the reservoir.
The heated heavy oil or bitumen including some dissolved CO2, the connate water and the steam condensate are mobilized toward the production wells 12', and then lifted to the surface for processing.
In the case where the reservoir 2 is entirely a bitumen reservoir; the CO2 can be produced from the top of the reservoir to maintain a predetermined and/or approved safe steam chamber pressure. The produced CO2 can be conditioned for sequestration, possibly dehydration and liquefaction.
- 16 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 The required energy (net) is estimated as the sum of the vaporization energy of the injected water 26, plus any water from zone 4.
During and after the SEOR process, produced fluids from the production wells 12' are lifted to the surface are then pipelined to a processing plant. The produced fluid can be degassed and the produced liquid is transferred to the free water knock out. The produced free water can be separated out in the free water knock out and is transferred to the produced water tank or vessel.
A treater breaks the produced emulsion to produce pipeline specification bitumen that can be blended with diluent. The separated, produced water can be transferred from the treater to the produced water tank or vessel. Produced water can then be transferred from the produced water tank or vessel to the water injection wells 18 at the well pads. If needed, the produced water can be filtered at the exit discharge from the produced water tank or vessel and preheated using heat exchangers with hot produced fluids.
Natural gas and oxygen or air can be pipelined in separate pipelines to the well pads and then to the combined well 20. If oxygen is used, an oxygen plant that produces oxygen from the atmosphere can be used. If CO2 gas is removed or produced from the steam chamber via the water injection well 18, then the produced CO2 gas can be dehydrated and liquefied for sequestration into an abandoned SAGD or SEGD chamber, or into an aquifer.
When the reservoir 2 has been re-pressured and mixing of CO2 solvent and oil has occurred, produce some or all of the surrounding wells PW and/or drill and produce new vertical or horizontal production wells 12'. Production of the surrounding wells could be continuous or cyclic if needed.
It can be appreciated that if a horizontal production SEGD well is located vertically below and vertically aligned with the combustion well 20 as per SEGD, this SEGD
production well may become unproductive, be shut in or may be converted to a secondary combustion well.
In the exemplary, most of Saskatchewan and Alberta heavy oil is extracted using the CHOP process or foamy oil production using horizontal wells¨ pressure depletion, foamy oil without or with sand production and wormholes. Overall recovery factor is very low - <7% initial oil in place (I0IP) primary and ¨2% IOIP more for current enhanced recovery for Saskatchewan, 11.1% for Alberta.
There are many advantages of the SEOR process of the present technology over the known SEGD and/or SAGD processes. The SEOR process of the present technology has higher energy efficiency by way of direct combustion and heating of the steam chamber, with no heat losses and
During and after the SEOR process, produced fluids from the production wells 12' are lifted to the surface are then pipelined to a processing plant. The produced fluid can be degassed and the produced liquid is transferred to the free water knock out. The produced free water can be separated out in the free water knock out and is transferred to the produced water tank or vessel.
A treater breaks the produced emulsion to produce pipeline specification bitumen that can be blended with diluent. The separated, produced water can be transferred from the treater to the produced water tank or vessel. Produced water can then be transferred from the produced water tank or vessel to the water injection wells 18 at the well pads. If needed, the produced water can be filtered at the exit discharge from the produced water tank or vessel and preheated using heat exchangers with hot produced fluids.
Natural gas and oxygen or air can be pipelined in separate pipelines to the well pads and then to the combined well 20. If oxygen is used, an oxygen plant that produces oxygen from the atmosphere can be used. If CO2 gas is removed or produced from the steam chamber via the water injection well 18, then the produced CO2 gas can be dehydrated and liquefied for sequestration into an abandoned SAGD or SEGD chamber, or into an aquifer.
When the reservoir 2 has been re-pressured and mixing of CO2 solvent and oil has occurred, produce some or all of the surrounding wells PW and/or drill and produce new vertical or horizontal production wells 12'. Production of the surrounding wells could be continuous or cyclic if needed.
It can be appreciated that if a horizontal production SEGD well is located vertically below and vertically aligned with the combustion well 20 as per SEGD, this SEGD
production well may become unproductive, be shut in or may be converted to a secondary combustion well.
In the exemplary, most of Saskatchewan and Alberta heavy oil is extracted using the CHOP process or foamy oil production using horizontal wells¨ pressure depletion, foamy oil without or with sand production and wormholes. Overall recovery factor is very low - <7% initial oil in place (I0IP) primary and ¨2% IOIP more for current enhanced recovery for Saskatchewan, 11.1% for Alberta.
There are many advantages of the SEOR process of the present technology over the known SEGD and/or SAGD processes. The SEOR process of the present technology has higher energy efficiency by way of direct combustion and heating of the steam chamber, with no heat losses and
- 17 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 steam losses in flue gases and in all surface equipment. The emissions are reduced with CO2 gas sequestration, and no combustion emissions of CO2, CO, NOx and/or SOx.
The SEOR process of the present technology has less to no make-up water as compared to SAGD or steam injection, and has negligible to no disposed water. Water treatment is less complex and cost effective, and may require only filtration. For steam generation, the SEOR process may use surface boilers or once through steam generators but only for a short initial period to create a small steam chamber to the top of the reservoir.
The known SEGD process was previously not advantageous or contemplated for utilization with post CHOP wells or thin oil payzones that require significant height for proper gravity drainage. The present technology utilizes at least in part some of the SEGD
system and method to extract a significant amount of the billions of barrels of unrecoverable oil from thin oil payzones or partially depleted formations.
Some potential benefits and unexpected results of utilizing the SEOR system and method are:
The utilization of a combined SEOR and SEGD process.
Utilizing steam, CO2 and/or hot water to push oil laterally toward nearby vertical and/or horizontal productions wells.
CO2 re-pressurization of the reservoir.
CO2 solubility into and viscosity reduction of the oil.
Collapsing of wormholes created during previous oil extraction processes by viscosity reduction of the oil by CO2 and heat, and further collapsing by rapid depressurization.
Collapsed wormholes are permeable allowing oil to flow toward the production wells.
Enhanced foamy oil production from existing wells.
CO2/WAG EOR in the waterflood reservoirs.
CO2 capture and sequestration in the reservoirs.
Further in the exemplary, the amount of unrecovered oil left behind by heavy oil extraction is significant, as shown in Table 1 illustrating heavy oil data of Saskatchewan and Alberta heavy oil fields.
Area Initial Oil in Recoverable Re coverabl Unrecoverable Unrecoverable Place (I0IP) Oil, e Oil, Oil, Oil, billion barrels billion barrels %IOIP billion barrels %IOIP
Lloydminster -1H 20.70 1.83 8.8 18.9 91.2 Kindersley - 2H 5.35 0.55 10.3 4.8 89.7
The SEOR process of the present technology has less to no make-up water as compared to SAGD or steam injection, and has negligible to no disposed water. Water treatment is less complex and cost effective, and may require only filtration. For steam generation, the SEOR process may use surface boilers or once through steam generators but only for a short initial period to create a small steam chamber to the top of the reservoir.
The known SEGD process was previously not advantageous or contemplated for utilization with post CHOP wells or thin oil payzones that require significant height for proper gravity drainage. The present technology utilizes at least in part some of the SEGD
system and method to extract a significant amount of the billions of barrels of unrecoverable oil from thin oil payzones or partially depleted formations.
Some potential benefits and unexpected results of utilizing the SEOR system and method are:
The utilization of a combined SEOR and SEGD process.
Utilizing steam, CO2 and/or hot water to push oil laterally toward nearby vertical and/or horizontal productions wells.
CO2 re-pressurization of the reservoir.
CO2 solubility into and viscosity reduction of the oil.
Collapsing of wormholes created during previous oil extraction processes by viscosity reduction of the oil by CO2 and heat, and further collapsing by rapid depressurization.
Collapsed wormholes are permeable allowing oil to flow toward the production wells.
Enhanced foamy oil production from existing wells.
CO2/WAG EOR in the waterflood reservoirs.
CO2 capture and sequestration in the reservoirs.
Further in the exemplary, the amount of unrecovered oil left behind by heavy oil extraction is significant, as shown in Table 1 illustrating heavy oil data of Saskatchewan and Alberta heavy oil fields.
Area Initial Oil in Recoverable Re coverabl Unrecoverable Unrecoverable Place (I0IP) Oil, e Oil, Oil, Oil, billion barrels billion barrels %IOIP billion barrels %IOIP
Lloydminster -1H 20.70 1.83 8.8 18.9 91.2 Kindersley - 2H 5.35 0.55 10.3 4.8 89.7
- 18 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 Sask Heavy 26.05 2.38 9.1 23.7 90.9 Alta Heavy 12.15 1.35 11.1 10.8 88.9 Primary Table 1 - Saskatchewan Heavy Oil Data As appreciated by Table 1, there are billions of barrels of oil that were previously thought as unrecoverable. The SEOR process is unique in that it overcomes the disadvantages of known SEGD and/or SAGD processes to extract previously thought unrecoverable heavy oil from thin payzones or from depressurized wells due from previous extract processes.
It is known that steam and CO2 injection can result in a dramatic improvement in the rate of final oil recovery as compared to steam only injection. The addition CO2 to steam injection results in lowering the partial pressure of steam and reducing steam temperature, which can have an adverse effect on viscous oil recovery. On the other hand, CO2 solubility in the oil increases at the lower temperatures and higher pressures, which can be beneficial in reducing oil viscosity and increasing oil swelling. However, separately injecting steam and CO2 requires additional wells to be drilled and/or more complicated machinery at the surface. This results in higher costs and longer setup times.
Taking for example the Lloydminster area, which is located in east-central Alberta and west-central Saskatchewan, contains a large amount of heavy oil resources in a series of thin oil belts with less than 10m payzones. Such a thin payzone makes the use of SAGD and cyclic steam stimulation processes undesirable, uneconomical and in some cases not applicable. This in part due to the excessive heat losses and limited drainage height. An alternative option in such formations is to use solvent injection, such as CO2, to dilute and/or swell the heavy oil.
The utilization of CO2 to decrease the viscosity of heavy oil and its advantages is known, as described by Xiaoli Li, Daoyong Tony Yang and Zhaoqi Fan (University of Regina) in a published article entitled Phase Behaviour and Viscosity Reduction of CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures (Document ID: SPE-170057-MS; Publisher:
Society of Petroleum Engineers; Source: SPE Heavy Oil Conference-Canada, 10-12 June, Calgary, Alberta, Canada; Publication: Date2014). The advantage of CO2 was quantified utilizing the two-parameter double-logarithm relation (see Equation 1) to accurately reproduce the measured viscosity of the Lloydminster heavy oil at the atmospheric pressure and various temperatures.
It is known that steam and CO2 injection can result in a dramatic improvement in the rate of final oil recovery as compared to steam only injection. The addition CO2 to steam injection results in lowering the partial pressure of steam and reducing steam temperature, which can have an adverse effect on viscous oil recovery. On the other hand, CO2 solubility in the oil increases at the lower temperatures and higher pressures, which can be beneficial in reducing oil viscosity and increasing oil swelling. However, separately injecting steam and CO2 requires additional wells to be drilled and/or more complicated machinery at the surface. This results in higher costs and longer setup times.
Taking for example the Lloydminster area, which is located in east-central Alberta and west-central Saskatchewan, contains a large amount of heavy oil resources in a series of thin oil belts with less than 10m payzones. Such a thin payzone makes the use of SAGD and cyclic steam stimulation processes undesirable, uneconomical and in some cases not applicable. This in part due to the excessive heat losses and limited drainage height. An alternative option in such formations is to use solvent injection, such as CO2, to dilute and/or swell the heavy oil.
The utilization of CO2 to decrease the viscosity of heavy oil and its advantages is known, as described by Xiaoli Li, Daoyong Tony Yang and Zhaoqi Fan (University of Regina) in a published article entitled Phase Behaviour and Viscosity Reduction of CO2-Heavy Oil Systems at High Pressures and Elevated Temperatures (Document ID: SPE-170057-MS; Publisher:
Society of Petroleum Engineers; Source: SPE Heavy Oil Conference-Canada, 10-12 June, Calgary, Alberta, Canada; Publication: Date2014). The advantage of CO2 was quantified utilizing the two-parameter double-logarithm relation (see Equation 1) to accurately reproduce the measured viscosity of the Lloydminster heavy oil at the atmospheric pressure and various temperatures.
- 19 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 tog ic, pogiG GO] = ¨3.7042 tog 10(T) + 9.7600 (1) where p is viscosity of the heavy oil in cP and T is temperature in K. The viscosity of Lloydminster heavy oil at ambient temperature (i.e., 298.15 K) and pressure (i.e., 101.325 kPa) is calculated to be 8477.1 cP.
It is apparent that a key recovery mechanism of CO2 is viscosity reduction.
This is evident by the graph as shown in FIG. 10 provided in the above-identified publication to Li et al. that illustrates the viscosity of Lloydminster heavy oil and the CO2 saturage of heavy oil feed #1.
Consequently, the use of CO2 saturation substantially reduces the viscosity of heavy oil thereby supporting the advantages of the SEOR method of the present technology. However and in contrast with known methods, the SEOR method avoids the disadvantage of generating steam and injecting CO2 from the surface by creating the steam and CO2 in situ with minimal resources since the injected water can be water produced from previous processes, and combustion is created in situ utilizing recoverably natural gas and oxygen or air.
Previous solutions have been known to force a tight packing of reservoir sand in an annulus around the well by collapsing the reservoir sand into that open space. This was previously accomplished by depressuring the wellbore as rapidly as possible by displacing out any fluids in the wellbore with nitrogen, then opening the well to atmosphere at the surface.
This process is again costly and time consuming in light of the present SEOR method.
The SEOR method automatically collapses the wormholes as a result of the CO2 saturation, with the CO2 being a product of the in situ combustion. No additional gas injection, such as nitrogen, is required.
While embodiments of the sustainable enhanced oil recovery of heavy oil has been described in detail, it should be apparent that modifications and variations thereto are possible, all of which fall within the true spirit and scope of the invention. With respect to the above description then, it is to be realized that the optimum dimensional relationships for the parts of the invention, to include variations in size, materials, shape, form, function and manner of operation, assembly and use, are deemed readily apparent and obvious to one skilled in the art, and all equivalent relationships to those illustrated in the drawings and described in the specification are intended to be encompassed by the present technology. And although producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation have been described, it should be appreciated that the sustainable enhanced oil recovery of heavy oil herein described is
It is apparent that a key recovery mechanism of CO2 is viscosity reduction.
This is evident by the graph as shown in FIG. 10 provided in the above-identified publication to Li et al. that illustrates the viscosity of Lloydminster heavy oil and the CO2 saturage of heavy oil feed #1.
Consequently, the use of CO2 saturation substantially reduces the viscosity of heavy oil thereby supporting the advantages of the SEOR method of the present technology. However and in contrast with known methods, the SEOR method avoids the disadvantage of generating steam and injecting CO2 from the surface by creating the steam and CO2 in situ with minimal resources since the injected water can be water produced from previous processes, and combustion is created in situ utilizing recoverably natural gas and oxygen or air.
Previous solutions have been known to force a tight packing of reservoir sand in an annulus around the well by collapsing the reservoir sand into that open space. This was previously accomplished by depressuring the wellbore as rapidly as possible by displacing out any fluids in the wellbore with nitrogen, then opening the well to atmosphere at the surface.
This process is again costly and time consuming in light of the present SEOR method.
The SEOR method automatically collapses the wormholes as a result of the CO2 saturation, with the CO2 being a product of the in situ combustion. No additional gas injection, such as nitrogen, is required.
While embodiments of the sustainable enhanced oil recovery of heavy oil has been described in detail, it should be apparent that modifications and variations thereto are possible, all of which fall within the true spirit and scope of the invention. With respect to the above description then, it is to be realized that the optimum dimensional relationships for the parts of the invention, to include variations in size, materials, shape, form, function and manner of operation, assembly and use, are deemed readily apparent and obvious to one skilled in the art, and all equivalent relationships to those illustrated in the drawings and described in the specification are intended to be encompassed by the present technology. And although producing hydrocarbons from a heavy oil formation or reservoir using in situ steam and carbon dioxide generation have been described, it should be appreciated that the sustainable enhanced oil recovery of heavy oil herein described is
- 20 -Date Recue/Date Received 2020-12-02 Docket No.: 205-19 also suitable for producing oil from new formations and or formations that have previously been processed using other methods from those described herewith in the exemplary.
Therefore, the foregoing is considered as illustrative only of the principles of the invention.
Further, since numerous modifications and changes will readily occur to those skilled in the art, it is not desired to limit the invention to the exact construction and operation shown and described, and accordingly, all suitable modifications and equivalents may be resorted to, falling within the scope of the invention.
Therefore, the foregoing is considered as illustrative only of the principles of the invention.
Further, since numerous modifications and changes will readily occur to those skilled in the art, it is not desired to limit the invention to the exact construction and operation shown and described, and accordingly, all suitable modifications and equivalents may be resorted to, falling within the scope of the invention.
- 21 -Date Recue/Date Received 2020-12-02
Claims (24)
1. A method for recovering hydrocarbon material from a subterranean formation containing hydrocarbon material, the method comprising:
a) providing a first well in the formation, and a second well in the formation vertically displaced from the first well;
b) injecting water into the formation from the first well;
c) injecting a fuel and air or oxygen into an interior of the second well;
d) combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases;
e) contacting the water with the combustion gas or gases in the formation to vaporize the water to create steam;
f) repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen;
g) contacting the combustion gas or gases with the hydrocarbon material in the formation to reduce the viscosity of the hydrocarbon material for mobilizing the hydrocarbon material toward a third well; and h) producing the mobilized hydrocarbon material from the third well in the formation laterally displaced from the first and second wells.
a) providing a first well in the formation, and a second well in the formation vertically displaced from the first well;
b) injecting water into the formation from the first well;
c) injecting a fuel and air or oxygen into an interior of the second well;
d) combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases;
e) contacting the water with the combustion gas or gases in the formation to vaporize the water to create steam;
f) repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen;
g) contacting the combustion gas or gases with the hydrocarbon material in the formation to reduce the viscosity of the hydrocarbon material for mobilizing the hydrocarbon material toward a third well; and h) producing the mobilized hydrocarbon material from the third well in the formation laterally displaced from the first and second wells.
2. The method of claim 1, wherein the first and second wells are horizontal wells.
3. The method of claims 1 or 2, wherein the third well is a plurality of vertical wells located around the first and second wells.
4. The method of claims 1 or 2, wherein the third well is a plurality of horizontal wells located laterally offset from the second well.
5. The method of any one of claims 1 to 4, wherein step a) is conducted after a previous hydrocarbon production process was conducted on the formation that created wormholes, wherein the hydrocarbon material is heavy oil.
6. The method of claim 5 further comprising a step of collapsing the wormholes formed during the previous process by the introduction of the combustion gas or gases into the wormholes.
7. The method of claim 6 further comprising the step of collapsing the wormholes further by depressuring at the third well.
8. The method of claim 6, wherein the previous process is selected from the group consisting of a cold heavy oil production process, waterflooding, bottom water drive, and top gas drive.
9. The method of any one of claims 1 to 8, wherein the fuel is a hydrocarbon fuel.
10. The method of claim 9, wherein the hydrocarbon fuel is natural gas.
11. The method of any one of claims 1 to 9, wherein the combustion gas or gases includes carbon dioxide.
12. The method of any one of claims 1 to 11, wherein the steam condenses to water and is produced along with the mobilized hydrocarbon material by the third well.
13. The method of claim 12, wherein the water produced by the third well is recirculated for injection into the formation by way of the first well.
14. A method for recovering heavy oil from a subterranean formation that has undergone a previous hydrocarbon production process to the subterranean formation that created womiholes, the method comprising:
a) utilizing a first well in the formation as an injection well, and a second well in the formation vertically displaced from the first well as a combustion well;
b) injecting water into the formation from the first well;
c) injecting a fuel and air or oxygen into an interior of the second well;
d) combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases that exits the second well and travels into the formation;
e) creating steam in the formation by contacting the water with the combustion gas or gases to vaporize at least part of the water;
f) repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen;
g) collapsing the wormholes created by the previous process by the combustion gas or gases being introduced into the wormholes or an area surrounding the wormholes;
h) contacting the combustion gas or gases with the heavy oil in the formation to reduce the viscosity of the heavy oil for mobilizing the heavy oil toward a third well;
and i) producing the mobilized heavy oil from the third well in the formation laterally displaced from the first and second wells.
a) utilizing a first well in the formation as an injection well, and a second well in the formation vertically displaced from the first well as a combustion well;
b) injecting water into the formation from the first well;
c) injecting a fuel and air or oxygen into an interior of the second well;
d) combusting the fuel and the air or oxygen in the second well to create a combustion gas or gases that exits the second well and travels into the formation;
e) creating steam in the formation by contacting the water with the combustion gas or gases to vaporize at least part of the water;
f) repressurizing the formation with the combustion gas or gases to a pressure greater than a pressure prior to combusting the fuel and the air or oxygen;
g) collapsing the wormholes created by the previous process by the combustion gas or gases being introduced into the wormholes or an area surrounding the wormholes;
h) contacting the combustion gas or gases with the heavy oil in the formation to reduce the viscosity of the heavy oil for mobilizing the heavy oil toward a third well;
and i) producing the mobilized heavy oil from the third well in the formation laterally displaced from the first and second wells.
15. The method of claim 14, wherein the first and second wells are horizontal wells.
16. The method of claims 14 or 15, wherein the third well is a plurality of vertical wells located around the first and second wells.
17. The method of claims 14 or 15, wherein the third well is a plurality of horizontal wells located laterally offset from the second well.
18. The method of claim 14, wherein the previous process is selected from the group consisting of a cold heavy oil production process, waterflooding, bottom water drive, and top gas drive.
19. The method of any one of claims 14 to 18 wherein the fuel is a hydrocarbon fuel.
20. The method of claim 19, wherein the hydrocarbon fuel is natural gas.
21. The method of any one of claims 14 to 20, wherein the combustion gas or gases includes carbon dioxide.
22. The method of any one of claims 14 to 21, wherein the steam condenses to water and is produced along with the heavy oil material by the third well.
23. The method of claim 22, wherein the water produced by the third well is recirculated for injection into the formation by way of the first well.
24. The method of any one of claims 14 to 23 further comprising the step of collapsing the womiholes further by depressuring at the third well.
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