method for recovering a deposit of combustible material from a formation, apparatus for producing a

专利摘要:
METHOD TO RECOVER A FUEL MATERIAL DEPOSIT FROM A FORMATION, APPARATUS TO PRODUCE A CO2 CONTAINING FLOW AT THE BOTTOM OF THE WELL IN A WELL, AND SYSTEM TO GENERATE CO2 AND RECOVER SUCH DEPOSIT. The present invention relates to systems, apparatus and methods for providing a safe, high purity source of CO2 that is used in the recovery of formation deposits such as fossil fuels. At least a portion of recovered fossil fuels can be directly burned or extracted using the same process used to provide the pure source of CO2 without the need to first remove CO2, sulfur, other fossil fuels, or other impurities.
公开号:BR112013008113B1
申请号:R112013008113-9
申请日:2011-09-20
公开日:2021-04-20
发明作者:Miles R. Palmer；Rodney John Allam；Jeremy Eron Fetvedt；David Arthur Freed；Glenn William Jr. Brown
申请人:Palmer Labs, Llc；8 Rivers Capital, Llc；
IPC主号:

专利说明:

FIELD OF THE INVENTION
[001] The present invention relates to systems and methods for using CO2 in the recovery of formation deposits. In particular, the invention provides systems and methods for directing CO2 from a combustion process into a geological formation to facilitate the recovery of one or more formation deposits from the geological formation, such as combustible material deposits. BACKGROUND OF THE INVENTION
[002] Numerous materials useful for energy production are found naturally in the earth. For example, fossil fuels (eg crude oil, natural gas and coal) are located as deposits in various rock formations around the world and man has been recovering such materials for many years through mining, drilling and the like. As the most readily obtainable deposits are depleted, advanced techniques to facilitate the recovery of useful materials are continually being sought.
[003] As an example, the use of fluids and fluidized mixtures to improve the recovery of various fossil fuels has been in development for several years. Mechanisms for enhanced recovery are generally based on improving the flow of fossil fuels through their surrounding geological formation towards an extraction well. Three prevalent mechanisms for improving fossil fuel recovery in this way include the following: 1) using fluids to create and sustain fractures in rock formations to promote freer flow passages; 2) rely on the injection of fluids for volumetric displacement or pressurized fossil fuel; and 3) mixing the fluid with the fossil fuel so that one or both the density and viscosity of the fossil fuel are reduced. Viscosity can also be reduced by mixing other materials into the fossil fuel, heating the fossil fuel, or both. All of these mechanisms involve injecting material into a well or wells, and then obtaining increased fossil fuel production from injection into a well or wells (or from one or more other wells in the vicinity).
[004] Fracturing as a method to improve fossil fuel recovery is done from a well drilled in a rock formation reservoir. A hydraulic fracture can be formed by pumping the fracture fluid into the well at a rate sufficient to increase the pressure at the bottom of the well to an amount in excess of the fracture gradient of the formation rock. The pressure causes the formation to rupture, allowing fluid from the fracturing to enter and extend the rupture further into the formation. To keep this fracture open after stopping the injection, a solid material to keep an induced hydraulic fracture open (proppant) is usually added to the fracture fluid. Solid material to hold an open induced hydraulic fracture, which is commonly sieved round sand, is transported into the fracture. This sand is chosen to be greater in permeability than the surrounding formation, and the sustained hydraulic fracture then becomes a high permeability conduit through which formation fluids can flow into the well. A variety of fluids are proposed and used such as fracture fluids, displacement fluids, and viscosity conduction fluids to improve recovery for fossil fuel reservoirs. Existing methods, however, employ fluids with highly controversial environmental impacts, less than the desired effectiveness, or high cost, or a combination of these factors. Some environmental and human health concerns that are suggested to be associated with the fluids typically used in prior art hydraulic fracturing include potential mishandling of toxic solid waste, potential risks to air quality, potential groundwater contamination, and migration unintended hydraulic fracturing gases and chemicals to the surface within a given radius of drilling operations.
[005] Fluids such as water and steam, with or without surfactants and with or without high heat values, often show less than the desired performance to improve fossil fuel recovery. The main reasons are that water can be much denser than certain fossil fuels, and water is a liquid under equilibrium conditions. Such chemical factors greatly limit or eliminate miscibility and mixing between water/vapour and the hydrophobic fossil fuel, thus limiting or greatly eliminating any reduction in the viscosity of the fossil fuel. The higher density of water can lead to the initial physical displacement of the fossil fuel, but this effect is often limited in time and effectiveness to an undesirable extent. Denser water can flow down and out from the fossil fuel reservoir, quickly diminishing or eliminating any displacement effect.
[006] Supercritical carbon dioxide can be highly useful to improve oil recovery. Specifically, the supercritical fluid nature and the chemical nature of the material make it miscible with oil to decrease oil viscosity and density, and/or improve oil flow through the formation. Also, the density of supercritical carbon dioxide is substantially lower than the density of water, and therefore tends to rise into the fossil fuel reservoir rather than flowing down as water does denser. Furthermore, the material properties of supercritical CO2 allow it to function as a better solvent or other materials as well. Specifically, as compared to gaseous or liquid CO2, supercritical CO2 demonstrates material properties that can substantially increase its dissolution properties. Currently, in order to use supercritical carbon dioxide in recovery methods, CO2 must be transported from its source (whether natural or anthropogenic) to a site of use.
[007] As much as 70% of the oil currently in formations is unrecoverable without the use of enhanced oil recovery methods, particularly CO2-driven EOR. Despite its potential, there are several limiting factors with EOR in current technique. First, industrial creation of purified CO2 is excessively expensive to separate, purify and compress in use for EOR as it typically requires large capital and operating investments in the form of system additions such as amine and/or other solvent purifiers. . Even afterwards, the CO2 needs to be compressed to a pressure sufficient to inject into the well. These systems are not only expensive and potentially harmful to the environment, but they also require energy, thus limiting the effectiveness of the total system. Second, piping networks are necessary and not sufficient in most locations where EOR is a possibility, thus limiting your exposure to a significant number of formations. In current cases, the pipeline networks are fed from geological CO2 sources. However, these are extremely limited in location and amounts of CO2 available.
[008] Furthermore, against an economic and political backdrop where CO2 emissions are tightly monitored and always discouraged, it is generally undesirable to open up CO2 deposits that are already geologically sequestered.
[009] When fossil fuels are removed from underground deposits using enhanced recovery methods, they often contain dissolved CO2 and other impurities that must be separated using processes such as absorption processes. These may include the following: chemical, physical and/or solid surface processes; physical separation through membrane or cryogenic means; or hybrid solutions that offer mixed physical and chemical solvents. Such processes can include, but are not limited to, the expensive and ineffective Ryan/Holmes process, the Low Temperature Separator (LTX) process, the FLUOR amine process, the Selexol process, the Rectisol process, and others. These processes are used to remove the CO2 content of natural gas separated from the liquid oil so that the natural gas fraction (eg CH4 fraction) can be produced in sufficient purity for sale in piping systems and so that larger C2 and hydrocarbon fractions can be separated for sale. Furthermore, the processes can be used to process combustible gas and/or corrosive gas before they can be transported and reused. In some cases where the CO2 content is of sufficient quantity (eg greater than 30% by weight or partial pressure), the separated CO2 can be recycled to another EOR service. Specifically, with respect to other impurities, natural gas that contains high amounts of hydrogen sulfides (typically an H2S content exceeds 5.7 mg per cubic meter) is known as corrosive gas, and the H2S must be removed (ie, from so that the natural gas is "sweetened") using processes such as the amine process or the Claus process before injection into the pipelines. These impurity removal processes can have detrimental effects on the environment, system efficiency and overall recovery costs.
[0010] Even when CO2 is used for enhanced recovery, the recoverable fossil fuels present in a formation are eventually depleted. The CO2 injection system must then be dismantled and also removed to a new location, which may be too far away, or discontinued and scrapped. This requires the installation of CO2 transmission pipelines with significant permission, time and expense requirements. Alternatively, the disadvantages of moving CO2 to an injection site may still impede the economical and even successful use of CO2 in an enhanced recovery method for fossil fuel.
[0011] There is particularly a need for EOR methods to be applied to the recovery of very heavy oils, such as oil below 15 API gravity, and tar sands. Heavy oil deposits are often recovered by injecting steam produced from surface steam generators or as distributed steam from a steam-based power generation system. These systems are often old, ineffective and highly polluting, particularly with high CO2 emissions. Consequently, efforts are made to design a heat generating device that is compact enough to be contained within the well and that can burn a fossil fuel within a reservoir producing not only heat but also CO2 and steam which act to displace the oil. of lower viscosity heated. U.S. Patent No. 4,397,356 describes a downhole combustor in which a fuel and an oxidizer are burned within a burner that includes a catalytic section to ensure full combustion with no soot formation.
[0012] Such efforts, however, still do not achieve the goal of providing sufficient means to enhance the recovery of a wide variety of formation deposits in a wide variety of settings so that they are effective, economical, environmentally friendly, and easily mobilized for transport to different task locations as required. Consequently, there remains a need in the field for other systems and methods to improve the recovery of formation deposits that not only lessen the impact on the environment, but also possibly provide solutions to other existing power generation problems. SUMMARY OF THE INVENTION
[0013] The present invention provides systems and methods to enhance the recovery of a variety of formation deposits including, but not limited to, fossil fuels and other commodities. Beneficially, enhanced recovery can be achieved using CO2 that can be driven from a combustion process that can optionally provide energy while also providing the CO2 used in the improved recovery methods.
[0014] In various modalities related to fossil fuel recovery, CO2 can be used to create and sustain fractures in rock formations to promote freer flow passages for fossil fuels contained in the formations; to displace hydrocarbons (eg methane) from the surfaces of formations, such as in coal bed methane formations; to provide volumetric or pressurized displacement of fossil fuels within a formation; and to blend with the fossil fuel so that one or both of the fossil fuel's density and viscosity is reduced. Furthermore, CO2 (alone or with water, preferably in the form of steam, or other materials) can be used to reduce the viscosity of fossil fuel (eg heavy oils) by directly mixing with the fossil fuel or indirectly by heating the fossil fuel , or both.
[0015] The methods and systems of the invention utilizing CO2 to improve the recovery of combustible material deposits can demonstrate a variety of useful characteristics. For example, in some embodiments, spent CO2 can be obtained as a by-product (eg as a combustion product) from an energy generation process (eg burning a fossil fuel). In certain embodiments, CO2 can be supplied from an energy generation process at a pressure that is suitable for direct injection into a deposit formation, specifically a geological structure or rock formation. In other embodiments, CO2 can be supplied from an energy generation process at a location that is suitable for direct injection into the deposit formation. More specifically, such direct deposit can mean that any CO2 transmission pipeline associated with the CO2 transmission for injection may have a minimum to near zero length - eg less than about 10 miles, less than about 5 miles, less than about 1 mile, less than about 30,480 cm (1,000 feet), or less than about 3048 cm (100 feet). In other embodiments, the invention can provide a transportable CO2 generation system that can be installed at or near the CO2 point of use - for example, in the same field with one or more wells or even directly within a well. In other embodiments, the invention can provide a transportable CO2 generation system that can be easily disassembled, relocated and reassembled at one or more subsequent points of CO2 use after using the system at a first point. In still other embodiments, the invention can provide a transportable CO2 generation system that can be connected to the CO2 point of use without a pipeline or with a minimum length pipeline, as described elsewhere herein.
[0016] In various embodiments, the power generation process from which the CO2 is derived can be at least partially fueled using a separate stream from a fraction of combustible material recovered in accordance with a method of the invention. In certain embodiments, the separate stream (which may be a gas stream) can contain at least CO2, and the separate stream can be used without any process steps to remove hydrocarbon or contaminating components present before it is optionally compressed and become at least part of the fuel feed for an energy production process from which CO2 is derived. In preferred embodiments, a useful energy production process according to the invention can use CO2 as a working fluid.
[0017] The invention generally encompasses a process that produces CO2 and such a process can be used in order to produce electricity, which adds value. Optionally, the process can be substantially simplified for one combustor only. In this case, the cost of capital is extremely low. This case is great when the fuel cost is very low, such as in places where natural gas (NG) is burned, or when coal slurry is available as a low cost fuel.
[0018] In other embodiments, the combustor can be used for direct injection of CO2 (and/or optionally water) into a suitable reservoir for recovery of deposits, such as fossil fuels. Any combination of combustible gas, oxygen, water, nitrogen, argon, air, and other additives can be added inside a high-pressure, high-temperature combustor.
[0019] In one embodiment, CO2 (and/or water) as a result of combustion (above the ground or at the bottom of the well) can be directed into an appropriate reservoir for fossil fuel recovery. In another embodiment, CO2 (and/or water) can be directed through any combination of coolers, filters and pumps prior to injection into a fossil fuel recovery well. This modality can particularly be used only for the production of supercritical CO2 to enhance the recovery of fossil fuels from appropriate reservoirs. In these processes, carbon dioxide can be compressed at significant pressure - often in excess of 200 bar (20 MPa) for injection into underground formations that lose the pressure needed to facilitate the flow of fossil fuels, and other substances, to a well for removal . Carbon dioxide can act to suppress underground formation and acts as a natural surfactant to swell and/or remove oil and other fossil fuels from rock surfaces and pores. In the case of enhanced coal bed methane recovery (ECBMR) and other forms of natural gas recovery, coal beds and other underground structures are flooded or fractured with CO2. Again acting either to pressurize the well, break the rock to release the gas, or as a natural surfactant to remove the natural gas. In the case of coal bed methane, the CO2 displaces CH4 and various short-chain hydrocarbon gases associated with (eg adsorbed onto) the surfaces of coal particles, and CO2 itself then becomes adsorbed onto the coal, effectively sequestering CO2 in training.
[0020] In still other embodiments, the combustor may be specifically located at the bottom of the well to generate steam and/or heat in improved recovery applications such as EOR, particularly in formations where the API of the combustible material is below about about 20 as in tar sands. In a formation carrying combustible material, a water-cooled downhole combustor can generate steam and heat to remove the combustible material. In one embodiment, as a pressurized flow containing the combustible material leaves the reservoir, the flow goes through an expander and into a reservoir where heavy oil is removed. The water and/or CO2 is then directed through power-producing components to generate electricity, and CO2 is produced to dilute the fuels that go into the downhole combustor.
[0021] The present invention is particularly beneficial in that a reliable, consistent, high purity source of CO2 can be provided for use as a recovery fluid. Since the CO2 produced from the energy production process is directed to the recovery method, this beneficially prevents the immediate release of CO2 into the atmosphere as CO2 can certainly be sequestered in the fossil fuel reservoir (at least in part) after pumping downhole for recovery purposes and/or recycled through the process one or more times. Furthermore, the availability of a reliable, consistent, high purity source of CO2 can replace the use of environmentally harmful materials such as fracturing fluids as CO2 can be a readily available, cost-saving alternative to more toxic options.
[0022] In another modality, the CO2 stream exiting the well-bottom combustor or high-efficiency cycle can also be cooled with water to create a steam generator. The invention further provides the option of using water vapor as a transpiration fluid.
[0023] More specifically, the present invention may be directed to methods for recovering a deposit of combustible material from a formation. The method may comprise burning a fuel to provide a stream containing CO2 in which at least a portion of the CO2 is in a supercritical state. In other words, at least a portion of the flux can comprise supercritical CO2. The method may further comprise injecting at least a portion of the Co2 containing stream into the formation including the deposit of combustible material for recovery so that at least a portion of the combustible material in the formation and at least a portion of the CO2 stream flow from formation and within a recovery well.
[0024] In more particular modalities, it was noted that the method can take on a variety of features. Non-limiting examples of other embodiments are given below.
[0025] The stream containing CO2 can demonstrate a pressure of at least 7.5 MPa when the stream containing CO2 is injected into the formation.
[0026] The combustion step can be carried out above ground at a location that is a short distance (eg less than 5 km) from the site where the stream containing CO2 is injected into the formation.
[0027] Before being injected into the formation, the stream containing CO2 can be expanded through a turbine for power generation.
[0028] The stream containing CO2 from combustion can be injected into the formation without any intermediate compression, collection, or transport to the site where the stream containing CO2 is directed into the formation. Similarly, the stream containing CO2 can be injected directly into the formation without undergoing any intermediate processing.
[0029] The stream containing CO2 can be injected into the formation through an injection well. In addition, the combustion step can be carried out at the bottom of the well in the injection well.
[0030] The combustion step can be particularly carried out using a perspiration cooled combustor. More particularly, the method may comprise providing a fuel, an oxidant and a sweat fluid to the sweat cooled combustor. Even more particularly, the method may comprise supplying a working fluid to the combustor that is different from the transpiration fluid.
[0031] In certain embodiments, a method for recovering a deposit of combustible material from a formation according to the invention may comprise the following steps: providing a combustion fuel and an oxidant in a perspiration cooled combustor; burning combustion fuel to provide a stream containing CO2 comprising supercritical CO2; and injecting at least a portion of the CO2 containing stream into the formation including the combustible material deposit for recovery such that at least a portion of the combustible material in the formation and at least a portion of the CO2 stream flow from the formation and into of a recovery well.
[0032] In particular, combustion can be carried out above ground. Thus, combustion fuel and oxidizer can be supplied within a perspiration cooled combustor positioned above ground.
[0033] After combustion and before injection, the method may include expanding the stream containing CO2 through a turbine for power generation to form a stream containing expanded CO2. The stream containing expanded CO2 can be passed through a heat exchanger that cools the stream containing CO2 and/or through one or more separators that remove one or more minor components present in the stream containing CO2. Preferably, cooling is carried out first and separation follows sequentially thereafter.
[0034] Also prior to injection, the stream containing CO2 can be separated into an injection CO2 stream that is injected into the formation and a recycling CO2 stream that is supplied within the cooled combustor with perspiration as the working fluid. To this end, the method may further comprise one or more of the compression of the recycle CO2 stream by passing the stream through a compressor and heating the recycle CO2 stream by passing the stream through the heat exchanger which cooled the stream containing expanded Co2 . Consequently, the method can then encompass providing the recycling CO2 stream within the combustor as the working fluid. Preferably, the recycle CO2 stream can be supplied within the combustor at a pressure of at least about 2 MPa. In some embodiments, at least a portion of the recycle CO2 stream is supplied within the combustor as at least a portion of a transpiration fluid used to cool the perspiration-cooled combustor. It may also be preferable for the recycle CO2 stream to be supplied into the combustor at a specific purity level - for example having a purity of at least 95%/mol.
[0035] The pressure of the flow containing CO2 can vary throughout the method. For example, the stream containing expanded CO2 can have a pressure of at least 1.5 MPa. In addition, the stream containing CO2 injected into the formation can have a pressure of at least about 7.5 MPa. Pressure may be relevant to the CO2 state. Specifically, it may be preferable for the stream containing Co2 that is injected into the formation to comprise supercritical CO2. Similarly, combustion can be carried out in a specific temperature range - for example, at a temperature of at least about 400oC.
[0036] In particular embodiments, the fuel fuel and oxidant may be supplied within a perspiration cooled combustor that is positioned at the bottom of the well in a well that opens into a formation. In such embodiments, the invention may also comprise supplying water within the perspiration cooled combustor so that the stream containing CO2 still includes steam. Specifically, water can be supplied inside the perspiration cooled combustor as a perspiration coolant.
[0037] As noted above, the methods of the invention may further comprise receiving from the recovery well a recovery stream comprising the combustible material and CO2. Consequently, the methods may comprise separating the recovery stream into a recovered gas stream and a recovered liquid stream. Specifically, the recovered gas stream may comprise methane and CO2 (as well as, optionally, one or more of C2 hydrocarbons, C3 hydrocarbons and C4 hydrocarbons. The recovered liquid stream may specifically comprise petroleum (which particularly may be oil). crude, but does not exclude gaseous and/or solid forms of petroleum). In some embodiments, the recovered liquid stream can comprise a fluidized solid combustible material.
[0038] In certain embodiments, the methods of the invention may comprise directing at least a portion of the recovered gas stream to the combustor as at least a portion of the combustion fuel. To this end, separating may comprise directing the recovered stream through at least one pressure decrease stage at a defined pressure whereby one or more gas fractions of combustible material is extracted and the remaining fraction of the recovery stream at the defined pressure comprises liquid combustible material. In particular embodiments, one or more of the combustible material gas fractions may comprise CO2. Also, the methods may further comprise directing a fraction of combustible material comprising the CO2 to the combustor as at least a portion of the combustible material. The methods may also comprise passing the combustible material gas fraction through a compressor which increases the pressure of the combustible material gas fraction before it is introduced into the combustor. In specific embodiments, the separation can result in a plurality of gas fractions of combustible material, and each of the fractions can comprise CO2. In such embodiments, two or more of the plurality of combustible material gas fractions comprising CO2 may be combined and directed to the combustor as at least a portion of the combustion fuel. This may further comprise passing the combustible material gas fractions through a compressor which increases the pressure of the combustible material gas fractions before being introduced into the combustor. Such a compressor can specifically be a multistage compressor. Preferably, the separation steps will split substantially all of the CO2 from the recovery stream into one or more gas fractions of combustible material. For example, the gas fractions of combustible material comprising the CO2 can include at least about 95% by mass of the total CO2 present in the recovery stream.
[0039] If desired, the method may further comprise separating the recovered gas stream within a recovered hydrocarbon gas stream and a recovered non-hydrocarbon gas stream (e.g. separating at least a portion of Co2 from the gas fractions fuel). While this is not necessary in accordance with the invention, it may be desirable in specific embodiments and thus is encompassed by the methods of the invention.
[0040] In other embodiments, the invention can be characterized as providing a method of producing a stream containing CO2 downhole in a well. In particular, the method may comprise the following steps, supplying a combustion fuel and an oxidant in a perspiration cooled combustor positioned at the bottom of the well in a well that is in or around a formation including a combustible material deposit; provide a perspiration coolant within the combustor; and burning the fuel within the cooled combustor with perspiration in the presence of the perspiration coolant so as to provide a stream containing CO2 from an outlet of the combustor at a pressure of at least about 7.5 MPa and a temperature of at least minus about 400oC. Preferably, at least a portion of the CO2 containing stream comprises supercritical CO2.
[0041] In particular embodiments, the invention may encompass the use of a stream containing formed CO2 as a means of expanding a previously formed well and/or forming a separate path through a formation. Specifically, the methods may comprise directing the stream containing CO2 towards the formation such that the stream containing CO2 supplied from the combustor outlet pierces into the formation and creates a path therein. The method may also comprise advancing the combustor through the formed path.
[0042] Preferably, at least a portion of any stream containing CO2 formed may be injected into the formation including the combustible material deposit so that at least a portion of the combustible material in the formation and at least a portion of the stream containing CO2 from formation and into a recovery well. After that, recovery steps can be performed as discussed above.
[0043] The invention also provides a variety of systems and apparatus that can be useful to recover deposits from formations. For example, in certain embodiments, the invention can be characterized as providing an apparatus for producing a stream containing CO2 downhole in a well. In particular, the apparatus may comprise a perspiration cooled combustor, a fuel supply in fluid connection with the combustor, an oxidant supply in fluid connection with the combustor, a perspiration cooling supply in fluid connection with the combustor, a chamber inside a perspiration cooled combustor where fuel combustion takes place at a temperature of at least about 600oC to produce the stream containing CO2; and an outlet on the combustor that releases the stream containing CO2 from the combustor and into the well. In particular embodiments, the outlet may comprise a conical-shaped nozzle that concentrates the stream containing CO2 released from it. In other words, the nozzle focuses the stream containing CO2 into a narrowed stream compared to the output end of the combustor, the restricted stream demonstrating increased energy.
[0044] In other embodiments, the invention can be characterized as providing a CO2 generation system. Such a system can be used to recover a deposit of combustible material from a formation. For example, such a system may comprise the following components: a perspiration cooled combustor; a combustion fuel supply in fluid connection with the combustor; an oxidant supply in fluid connection with the combustor, a supply of refrigerant with perspiration in fluid connection with the combustor; a chamber within the perspiration cooled combustor configured to receive and burn combustion fuel to provide a stream containing CO2 comprising supercritical CO2; an injection component that releases the stream containing CO2 within the formation including the combustible material deposit so that at least a portion of the combustible material in the formation and at least a portion of the stream containing CO2 flow from the formation and into a recovery well as a recovery stream; and one or more processing components for processing the recovered combustible material and CO2 in the recovery stream.
[0045] In particular embodiments, the one or more processing components may comprise an expander that reduces the pressure of the recovery stream. More specifically, the expander may comprise a power generation turbine. Furthermore, the one or more processing components may comprise one or more separation units. More specifically, the separation unit can be a unit that separates a gas stream from a liquid stream. The injection component may comprise a pipeline extending into a well formed in the formation.
[0046] In specific embodiments, one or more of the combustion fuel supply, the oxidant supply and the transpiration coolant supply may comprise piping of sufficient dimensions to release the respective material at the bottom of the well in a well formed in the formation. In other embodiments, the transpiration-cooled combustor can be configured to use the bottom of the well in a well formed in the formation. Preferably, the system can be sufficiently modular in construction so that the system can be reconfigured between a transport state and a CO2 generation state. Such reconfiguration can particularly be accomplished in a matter of hours, days or weeks. BRIEF DESCRIPTION OF THE DRAWINGS
[0047] In order to aid in understanding the embodiments of the invention, reference will now be made to the accompanying drawings in which like numbers refer to like elements and which are not necessarily drawn to scale. The drawings are exemplary only and are not to be construed as limiting the invention.
[0048] Figure 1 provides a cross section of a typical geological formation conducting oil as a deposit and illustrates a system and method of improving oil recovery in the formation by burning a fuel in a downhole combustor located in a injection well in accordance with an embodiment of the invention to produce Co2 that is directed into the formation from the injection well to improve oil recovery through a production well with optional processing of the produced oil;
[0049] Figure 2 provides a cross section of a typical geological formation conducting natural gas as a deposit and illustrates a system and method for improving the recovery of natural gas in the deposit by burning a fuel in a surface combustor according to an embodiment of the invention to produce CO2 that is directed into the formation from an injection well to enhance natural gas recovery through a production well with optional processing of the produced natural gas;
[0050] Figure 3 provides a cross section of a portion of a typical geological formation carrying a fossil fuel and illustrates a system and method for improving fossil fuel recovery through combustion of a fuel to produce CO2 that is directed into the forming from an injection well, where the dual-combustor system and method is provided to facilitate the use of combustion fuels that can form ash or other particulate materials as a combustion product; and
[0051] Figure 4 provides a graph illustrating the effectiveness of a method of energy production according to an embodiment of the invention in which corrosive gas (i.e., natural gas with an H2S content) is used as a combustion fuel, the effectiveness being shown as a function of the H2S content in the crude oil recovery stream from which the corrosive gas was separated. DETAILED DESCRIPTION OF THE INVENTION
[0052] The invention will now be described more fully hereinafter by reference to various embodiments. These embodiments are provided so that this disclosure will be insightful and complete and will fully convey the scope of the invention to those skilled in the art. Of course, the invention can be embodied in many different forms and is not to be construed as limited to the embodiments described herein; of course, these modalities are provided so that this disclosure will satisfy the applicable legal requirements. As used in the report and the accompanying claims, the singular forms "an", "an", "the" include plural referents unless the context clearly states otherwise.
[0053] The present invention relates to systems and methods for providing a reliable, high purity source of CO2 that can be safely and effectively provided for use in enhancing the recovery of a variety of formation deposits, particularly combustible material deposits. In specific embodiments, the terms "deposit" and "forming deposit" may refer specifically to deposits of combustible material. As used herein, the term "combustible material" specifically can encompass any material that is recognized as providing energy, such as through combustion of the material, heat transfer, or other means by which the material's stored energy potential is realized. . A combustible material may encompass carbonaceous materials (including biomass, tailings materials, and the like), which may further encompass solid, liquid, and gaseous hydrocarbons (including in a form consisting entirely of hydrogen and carbon in a form that still includes elements or additional compounds - eg sulfur and oxygen - as part of the chemical structure of the hydrocarbon or as a physical mixture with the hydrocarbon). More specifically, a combustible material can be characterized as a fossil fuel, petroleum, crude oil, natural gas, coal, coke, bitumen, oil shale, tar sands and/or combinations thereof, and/or derivatives thereof. Other aspects of geological formations that meet the criteria described above, as may be recognizable to one of skill in the art having knowledge of the present invention, may also be encompassed by the present invention.
[0054] In various embodiments, the present invention can be characterized as comprising injecting CO2 or a stream containing CO2 into a formation. In this sense, injecting or injection can include a passive transmission of material in a formation. Since much of the action of transporting a liquid or gaseous material into a rock face or otherwise porous formation typically requires applied pressure to significantly permeate the formation, injecting can be characterized as including the application of a force, such as applied pressure. Since the combustor of the present invention can provide a high pressure combustion product flow, the inherent pressure of the combustion product produced may be sufficient to obtain injection of the combustion product flow (or a portion thereof) into a formation. In other embodiments, however, additional pressurization may be used, particularly if the flux of combustion product is expanded in an energy production method. Of course, additional expansion can also be used.
[0055] In certain embodiments, the CO2 used in the improved recovery of formation deposits can be produced from a combustion method or cycle in which a fuel is burned to provide a flux of combustion product comprising CO2. CO2 can be extracted from a combustion product stream and thus can be obtained in various states of purity. Advantageously, by carrying out specific processing steps, the isolated Co2 can be substantially completely pure. In some embodiments, however, CO2 can be used in accordance with the invention as an integrated component of a combustion product stream. In other words, as more fully discussed below, although CO2 arising from a combustion product stream can be purified to a defined degree prior to use, a combustion product stream containing CO2 can be used in the invention without substantial purification or without any purification (ie, direct injection of the combustion product stream, which can be characterized as the stream containing CO2). Combustion may or may not be a component of a large system or method, such as an energy production system or method. Thus, the CO2 used according to the invention can be produced from an energy production system or method. CO2 (either as a purified stream or as a component of a combustion product stream) can be directed for use in a recovery method as discussed in this document.
[0056] A system for supplying CO2 for use in an improved recovery method may comprise a combustor that is configured to produce Co2 through the combustion of a fuel. One aspect of combustion may be energy production, and the supply of CO2 for improved deposit recovery may occur after energy production, before energy product, or both after and before energy production. In some modalities, however, combustion can only be carried out to produce CO2 for improved deposit recovery. Accordingly, any system that burns a carbonaceous fuel and produces CO2 in the amounts and forms described herein can be configured for use in accordance with the present invention in light of the present disclosure.
[0057] Combustion as a means to produce CO2 may comprise the use of a high-efficiency fuel combustor (such as a perspiration cooled combustor) and optionally a quench fluid, which may also function as the cooling fluid transpiration, a mixing fluid, and/or a circulating fluid. Specifically, the circulation fluid may be provided in the combustor along with an appropriate fuel, any necessary oxidants, and any associated materials that may be useful for efficient combustion and/or for more improved recovery from deposits. In certain embodiments, the invention may comprise the use of a combustor operating at very high temperatures, e.g., in the range of about 1600°C, or other temperature ranges as disclosed herein), and the circulating fluid may be useful for moderating the temperature of a flux of combustion product exiting the combustor, if desired. Exemplary combustors useful in accordance with the invention are disclosed in US Publication No. 2011/0083435 and US Publication No. 2010/0300063, which disclosures are incorporated herein by reference in their entirety.
[0058] In some embodiment, combustion can be carried out under such conditions that the CO2 in the resulting combustion product stream is in a supercritical state. High temperature combustion can be particularly useful to provide a CO2 stream for use in improved recovery methods in light of the ability to achieve substantially complete combustion of fuel, maximum efficiency, and prevent the production of a substantial content of particulate matter or matter in other solid forms. In various embodiments, high temperature combustion can mean combustion at a temperature of at least about 400oC, at least about 600oC, at least about 800oC, at least about 1,000oC, at least about 1,200oC, at least about 1,300oC, at least about 1,400oC, at least about 1,500oC, at least about 1,600oC, at least about 1,750oC, at least about 2,000oC, at least about 2,500oC, or at least around 3000oC. In other embodiments, high temperature combustion may mean combustion at a temperature of about 1,200oC to about 5,000oC, from about 1,500oC to about 4,000oC, about 1,600oC to about 3,500oC, about 1,700 oC to about 3200oC, about 1800oC to about 3100oC, about 1900oC to about 3,000oC, or about 2,000oC to about 3,000oC.
[0059] The use of transpiration cooling in accordance with the present invention can be particularly useful to prevent corrosion, dirt and erosion in the combustor. This further allows the combustor to work in a sufficiently high temperature range to give complete or at least substantially complete combustion of the fuel that is used.
[0060] By way of example, a transpiration-cooled combustor useful in accordance with the invention may include a combustion chamber at least partially defined by a transpiration member, wherein the transpiration member is at least partially surrounded by a transpiration member. pressure containment. The combustion chamber may have an inlet portion and an opposite outlet portion. The inlet portion of the combustion chamber may be configured to receive fuel to be burned into the combustion chamber at a combustion temperature to form a combustion product. The combustion chamber can be further configured to direct the combustion product towards the outlet portion. The transpiration member may be configured to direct a transpiration substance therethrough towards the combustion chamber for buffering interaction between the combustion product and the transpiration member. Furthermore, the transpiration substance can be introduced into the combustion chamber to obtain a desired exit temperature of the combustion product. In particular embodiments, the perspiration substance may at least partially comprise the circulating fluid. The walls of the combustion chamber can be lined with a layer of porous material through which the perspiration substance is directed and flows, such as O2 and/or H2O. The perforated/porous nature of the transpiration cooled combustor can extend substantially completely (axially) from the inlet to the outlet so that the transpiration fluid is directed within substantially the entire length of the combustion chamber. In other words, substantially the entire length of the combustion chamber can be cooled with perspiration. In other combustors, the perforations/pores can be spaced at an appropriate density so that substantially uniform distribution of the perspiration substance is obtained (ie no "dead spot" where the flow or presence of the perspiration substance is lacking). The ratio of pore area to total wall area (porosity %) can be, for example, at least about 5%, at least about 10%, at least about 15%, at least about 20%, at least minus about 30%, at least about 40%, or at least about 50%. Array sizes from about 10 x 10 to about 10,000 x 10,000 per centimeter (inch) with porosity percentages from about 10% to about 80% can be used in some examples.
[0061] An exemplary combustor may comprise a combustion chamber defined by a transpiration member, which may be at least partially surrounded by a pressure containment member. In some cases, the pressure containment member may still be at least partially surrounded by a heat transfer jacket, wherein the heat transfer jacket may cooperate with the pressure containment member to define one or more channels therebetween. , through which a low pressure water flow can be circulated. Through an evaporation mechanism, the circulated water can thus be used to control and/or maintain a selected temperature of the pressure containment member, for example, in a range from about 100oC to about 250oC. In some aspects, an insulating layer may be disposed between the transpiration member and the pressure containment member.
[0062] In some circumstances, the sweating member may comprise, for example, an outer sweating member and an inner sweating member, the inner sweating member being disposed opposite the outer sweating member from the pressure containment member , and setting the combustion chamber. The outer transpiration member may be comprised of any suitable high temperature resistant material such as, for example, steel and steel alloys, including stainless steel and nickel alloys. In some cases, the outer transpiration member may be configured to define the first transpiration fluid supply passages extending therethrough from the surface thereof adjacent to the insulating layer to the surface thereof adjacent to the inner transpiration member . The first transpiration fluid supply passages may, in some cases, correspond to the second transpiration fluid supply passages defined by the pressure containment member, the heat transfer jacket and/or the insulating layer. The first and second transpiration fluid supply passages can thus be configured to cooperate to direct a transpiration fluid therethrough to the inner transpiration member.
[0063] The internal transpiration member can be comprised of, for example, a porous ceramic material, a perforated material, a laminated material, a porous mat comprised of fibers randomly oriented in two dimensions and ordered in the third dimension, or any other material suitable or combinations thereof demonstrating the required characteristics thereof as disclosed herein, viz., multiple flow passages or pores or other suitable openings for receiving and directing the transpiration fluid through the inner transpiration member. Non-limiting examples of porous and other ceramic materials suitable for such transpiration cooling systems include aluminum oxide, zirconium oxide, transformation-hardened zirconium, copper, molybdenum, tungsten, copper-infiltrated tungsten, tungsten-coated molybdenum, tungsten-coated copper tungsten, various high temperature nickel alloys, and rhenium sheathed or coated materials. Suitable material sources include, for example, Coors Tek Inc. (Golden, CO) (zirconium); UltraMet Advanced Materials Solutions (Pacoima, CA) (refractory material coatings); Orsan Sylvania (Danvers, MA) (tungsten/copper); and MarkeTech International, Inc. (Port Townsend, WA) (tungsten). Examples of perforated materials for such transpiration cooling systems include all of the above materials and suppliers (where the final perforated structures can be obtained, for example, by perforating an initially non-porous structure using methods known in the fabrication art). Examples of suitable laminated materials include all of the above materials and suppliers (where the final laminated structures can be obtained, for example, by laminating non-porous or partially porous structures to obtain the desired final porosity using methods known in the fabrication art) .
[0064] The purifying substance can be directed through the inner transpiration member so that the piercing substance forms a buffer layer (i.e. a "vapour wall") immediately adjacent to the inner transpiration member within the combustion chamber . In some cases, the transpiration fluid can be released at least at the pressure within the combustion chamber so that the rate of transpiration fluid flow within the combustion chamber is sufficient for the transpiration fluid to mix with and cool the products of combustion to form an outgoing fluid mixture at a desired temperature (eg, as low as 100°C in some embodiments to as great as about 2000°C in other embodiments).
[0065] A combustor apparatus useful in accordance with the invention may comprise various auxiliary components, such as components useful to supply various materials used in the combustion process. For example, the combustor can include an integrated mixing chamber in which fuel, circulating fluid (e.g., CO2 and/or water), oxidant, and any other materials needed to effect combustion can be combined in any combination. Alternatively, such materials can be blended external to the combustor and internal to the combustor in a substantially mixed state. In various embodiments, the combustor can include inlets for fuel, oxidant (eg, O2 or air), circulating fluid, and sweating fluid. In specific embodiments, the circulating fluid and the transpiration fluid can be the same material or mixtures of materials. An air separation or compression unit can be used to supply the oxidizer (eg, in a substantially purified state), and a fuel injector device can be provided to receive the oxidizer and combine it with a circulating CO2 fluid. and a fuel stream, which may comprise a gas, a liquid, a supercritical fluid, or a solid particulate fuel suspended in a high-density CO2 fluid.
[0066] In another aspect, a perspiration cooled combustor apparatus may include a fuel injector for injecting a pressurized fuel stream into the combustion chamber of the combustor apparatus, optionally in combination with the circulating fluid and/or the oxidant. The oxidizer (optionally enriched oxygen) and the stream containing CO2 can be combined as a homogeneous supercritical mixture.
[0067] In particular embodiments, a combustor according to the invention can assume a particular configuration that can facilitate specific uses, such as downhole combustion. For example, in some embodiments, it may be useful for the combustor to provide a focused product stream that is effective to partially or completely dissolve at least the portion of the formation that is incident to the portion of the combustor from which the combustion product stream flows. Specifically, the combustor may include a nozzle or similarly a conical-shaped segment that concentrates combustion products at a high pressure, high temperature flow when exiting the combustor. In such configurations, a downhole combustor according to the present invention can at least partially create a wellbore in the formation through which the combustor can proceed to inject supercritical CO2 into the surrounding formation.
[0068] In addition, the combustor may include an outer casing (eg a metal or ceramic material) in addition to the perspiration cooled configurations already described above. Such an outer wrap can provide structural protection against physical damage to the combustor (for example, from unintended contact with rock formations) and can further protect against the growth of organic materials or deposition of other contaminants from rock, soot, and other materials that can be expelled by the flux of combustion at the bottom of the well. In particular embodiments, the outer casing can also be protected from perspiration (which may be at a lower temperature than perspiration from the main burner wall). Such additional perspiration protection can be useful to protect and/or lubricate the wellbore device to facilitate passage through the formations.
[0069] A wide variety of materials can be used as a fuel in the combustor. For example, combustion to produce CO2 for enhanced recovery of formation deposits can be performed using any of the following: various classifications, types and derivatives of coal, wood, oil, fuel oil, natural gas, coal-based fuel gas, tar sands, bitumen, and the like. Even more materials that can be used as fuel can include biomass, algae, classified fuel solid tailings, asphalt, used tires, diesel, gasoline, jet fuel (JP-5, JP-4), gases derived from gasification or pyrolysis of hydrocarbonaceous material, ethanol, solid and liquid biofuels and the like. In embodiments where the formation deposits for recovery include a fossil fuel, it may be particularly beneficial for the fuel used in the combustor to be a component of the recovery stream returned from the formation deposit (e.g., natural gas, oil, or a fraction of oil recovered from a formation). Any of the above combustion fuels can be characterized as a carbonaceous fuel in that the material includes a carbon component.
[0070] Fuels can be processed in various ways before injecting into the combustion apparatus and can be injected at desired rates and pressures useful to obtain a flow of the desired combustion product. Such fuels may be in liquid, suspension, gel or paste form with appropriate fluidity and viscosity at ambient temperatures or at elevated temperatures. For example, a fuel can be supplied at a temperature of about 30oC to about 500oC, about 40oC to about 450oC, about 50oC to about 425oC, or about 75oC to about 400oC. Any solid combustible materials can be crushed or crumbled or otherwise processed to reduce particle sizes, as appropriate. A fluidizing or suspending medium can be added, as needed, to obtain a suitable shape (eg a carbon suspension) and meet the flow requirements for high pressure pumping. Naturally, a fluidizing medium may not be necessary depending on the form of fuel (ie liquid or gas). Likewise, circulated circulating fluid can be used as the fluidizing medium in some embodiments.
[0071] Combustion as a means for producing CO2 for improved recovery of formation deposits can be carried out making use of specific process parameters and components. Examples of high-efficiency combustion systems and methods that can be used in accordance with the present invention to produce CO2 are described in U.S. Patent Publication No. 2011/0179799, the disclosure of which is incorporated herein by reference in its entirety. Preferably, the combustion system does not require any further compression or removal of impurities prior to injection into pipelines or formations to improve recovery of deposits such as fossil fuels. The present invention can also be applied to other combustion processes that can accept a feed fuel stream containing a substantial amount of CO2.
[0072] In various embodiments of the invention, the combustor apparatus used in the enhanced recovery methods may be a location on the surface that is in proximity to the site for injection of produced Co2. A combustor located on the surface can be in a permanent, semi-permanent, or transportable state. For example, the combustor can be a component of an energy production system in which a fuel is burned (preferably at a high temperature) in the presence of a circulating fluid (particularly CO2) or other quench fluid that can moderate the temperature of the combustion product flow leaving the combustor so that the combustion product flow can be utilized in energy transfer for energy production. Specifically, the flux of combustion product can be expanded through at least one turbine to generate power. The expanded gas stream can be subjected to processing, as further described below, or it can be injected directly into the formation.
[0073] In various embodiments, it may be desirable for CO2 to be introduced into the combustor at a defined pressure and/or temperature. Specifically, it may be beneficial for the CO2 introduced into the combustor to have a pressure of at least about 2 MPa, at least about 5 MPa, at least about 8 MPa, at least about 10 MPa, at least about 12 MPa, at least about 15 MPa, at least about 18 MPa, or at least about 20 MPa. In other embodiments, the pressure can be about 2 MPa to about 50 MPa, about 5 MPa to about 40 MPa, or about 10 MPa to about 30 MPa. In addition, it may be beneficial for the CO2 introduced into the combustor to have a temperature of at least about 200oC, at least about 250oC, at least about 300oC, at least about 400oC, at least about 500oC, at least about 600oC, at least about 700oC, at least about 800oC, or at least about 900oC.
[0074] In some embodiments, it may be useful for the O2 supplied to the combustor to be substantially purified (ie, updated in terms of molar content of O2 relative to other components naturally present in the air). In certain embodiments, O2 may have a purity greater than 50%/mol, greater than about 75%/mol, greater than about 85%/mol, greater than about 90%/mol, greater than than about 95%/mol, greater than about 98%/mol, or greater than about 99%/mol. In other embodiments, the O2 can have a molar purity of about 85% to about 99.6%/mol, about 85% to about 99%/mol, or about 90% to about 98%/mol. . The recovery of total CO2 from carbon in the fuel favors the use of high purities in the range of at least about 99.5%/mol.
[0075] In certain embodiments, the amount of O2 supplied may be in excess of the indicated stoichiometric amount by at least about 0.1%/mol, at least about 0.25%/mol, at least about 0.5 %/mol, at least about 1%/mol, at least about 2%/mol, at least about 3%/mol, at least about 4%/mol, or at least about 5%/mol. In other embodiments, the amount of O2 supplied can be in excess of the indicated stoichiometric amount by about 0.1% to about 5%/mol, about 0.25% to about 4%/mol, or about from 0.5% to about 3%/mol.
[0076] The introduction of the circulation fluid and/or the transpiration fluid into the combustor can be useful to control the combustion temperature so that the flux of combustion product leaving the combustor has a desired temperature. For example, it may be useful for the flux of combustion product leaving the combustor to have a temperature of at least about 500oC, at least about 900oC, at least about 1,000oC, at least about 1,200oC, or at least around 1500oC. In some embodiments, the combustion product stream may have a temperature of about 100oC to about 2,000oC, about 150oC to about 1,800oC, about 200oC to about 1,600oC, about 200oC to about 1,400oC , about 200oC to about 1,200oC, or about 200oC to about 1,000oC.
[0077] The combustion product flow can be directed to a turbine where the combustion product flow is expanded to generate energy (eg, through a generator to produce electricity). The turbine may have an inlet for receiving the flux of combustion product and an outlet for releasing a turbine exhaust stream comprising CO2. A single turbine can be used in some embodiments, or more than one turbine can be used, the multiple turbines being connected in series or optionally separated by one or more other components, such as another combustion component, a compression component, a separator component, or similar. A stream originating from a combustion process is discussed in this document and the input/output of any of these components can be described as being a stream containing CO2 and can arise from one or more combustors.
[0078] Turbine inlet flow temperature may vary, such as to as high as 1350oC. In other embodiments, the present systems and methods may use a turbine inlet temperature in a much lower range, as described above. Furthermore, the flux of combustion product leaving the combustor may have a pressure that is closely aligned with the pressure of the circulating CO2 fluid entering the combustor. In specific embodiments, the combustion product flow can be at a temperature and pressure such that the CO2 present in the flow is in a supercritical fluid state. When the combustion product flow is expanded through the turbine, the flow pressure can be reduced. Such a pressure drop can be controlled so that the combustion product flow pressure is in a defined relationship with the turbine discharge flow pressure, for example, a ratio of less than about 12, less than about of 10, less than about 8, less than about 7. In other embodiments, the ratio of inlet pressure to outlet pressure in the turbine can be about 1.5 to about 12, about 2 to about from 10, about 3 to about 9, or about 4 to about 8.
[0079] In specific embodiments, it may be desirable for the combustion product stream to be under conditions such that the CO2 in the stream is no longer in a supercritical state, but is certainly in a gaseous state. For example, supplying C2 in a gaseous state can facilitate further processing of the stream before injecting into the formation. Thus, the turbine charge flow may have a pressure that is below the pressure where the CO2 may be in a supercritical state - that is, less than about 7.3 MPa, less than about 7 MPa, less than that about 6 MPa, less than about 5 MPa, less than about 4 MPa, less than about 3 MPa, less than about 2 MPa, or less than about 1.5 MPa. In other embodiments, the turbine discharge flow pressure can be about 1.5 MPa to about 7 MPa, about 3 MPa to about 7 MPa, or about 4 MPa to about 7 MPa. In specific embodiments, the turbine discharge stream pressure may be less than the CO2 condensing pressure at the cooling temperatures to be encountered by the stream (eg ambient cooling). In other embodiments, however, where cooling and/or separation may not be required or desired, it may be helpful for the turbine discharge flow pressure to be higher. For example, the pressure can be at least about 7.5 MPa, at least about 8 MPa, at least about 8.5 MPa, at least about 9 MPa, or at least about 10 MPa. In yet other embodiments, the turbine exhaust flow pressure can be at least about 1.5 MPa, at least about 2 MPa, at least about 3 MPa, at least about 4 MPa, or at least about 5 MPa.
[0080] Although the passage of combustion product flow through the turbine may lead to some decrease in quantity and temperature, the turbine discharge flow may be significantly similar to the temperature of the combustion product flow. For example, the turbine discharge stream may have a temperature of about 500oC to about 1000oC, about 600oC to about 1,000oC, about 700oC to about 1,000oC, or about 800oC to about 1,000oC . Due to the relatively high temperature of the combustion product stream, it may be beneficial for the turbine to be formed from materials capable of withstanding such temperatures. It may also be useful for the turbine to comprise a material that provides good chemical resistance to the type of secondary materials that may be present in the combustion product stream.
[0081] The combustion product flow (or turbine discharge flow in energy production modalities) may be in a condition for direct injection into the formation where improved recovery of a deposit is desired (meaning no need for other flux processing, such as removing impurities, etc.). In some embodiments, however, it may be desirable to still process the flux prior to injection. For example, where the CO2 stream is being injected into a well, into a pipeline, or into a formation that can usually be damaged by injecting high enough pressure, the CO2 from the combustion process can be modified in pressure. As indicated above, expansion in energy production can reduce the Co2 flow pressure; however, further pressure reduction may be desired, and such pressure reduction may be provided by passing through one or more power generation turbines. Other means for reducing pressure can also be used as would be recognized by one of skill in the art to the advantage of the present disclosure. Preferably, compression of the CO2 stream will not be required in light of the possible input of energy required. However, if useful, such as due to the specific geology of the formation structure or piping specifications, CO2 compression can be performed.
[0082] In some embodiments, it may be useful to adjust the temperature of the CO2 stream before injecting into the formation. As further discussed below, the use of a relatively high temperature flux can be useful, such as in improved heavy oil recovery. Since the present invention encompasses high temperature combustion systems and methods, however, it may be useful in some embodiments to cool the CO2 stream prior to injection.
[0083] In particular, it may be useful to pass the CO2 flux through at least one heat exchanger that cools the flux and provides an O2 flux having a temperature in a defined range. In specific modalities, the cooled CO2 can have a temperature lower than about 1,000oC, less than about 750oC, less than about 500oC, less than about 250oC, less than about 100oC, less than about 80oC, less than about 60oC, or less than about 40oC. In certain embodiments, it may be particularly useful for the heat exchanger to comprise at least two heat exchangers in series to recover the CO2 stream and cool it to a desired temperature. The type of heat exchanger used may vary depending on the flow conditions entering the heat exchanger. For example, since the CO2 stream may be at a relatively high temperature, it may be useful for the heat exchanger to directly receive the CO2 stream to be formed from high performance materials designed to withstand extreme conditions (eg , an INCONEL® alloy or similar material). The first heat exchanger in a series comprises a material capable of withstanding a consistent working temperature of at least about 400oC, at least about 600oC, at least about 800oC, at least about 1000oC. It may also be useful for one or more of the heat exchangers to comprise a material that provides good chemical resistance to the type of secondary materials that may be present in the combustion product stream. Appropriate heat exchangers may include those available under the HEATRIC® trademark (available from Meggitt USA, Houston, TX). In embodiments where the first heat exchanger in a series can transfer sufficient heat content from the CO2 stream, one or more other heat exchangers present in the series can be formed from more conventional materials - eg stainless steel. In specific embodiments, at least two chlorine exchangers or at least three heat exchangers are used in a series to cool the turbine discharge stream to the desired temperature.
[0084] In some embodiments, it may be desirable for the CO2 stream from the combustion method to undergo further processing to separate any secondary components that remain in the CO2 stream. Such minor components may or may not be present, particularly depending on the nature of the fuel used in the combustion method. Likewise, it may or may not be desirable to separate any minor components present in the CO2 stream depending on the formation into which it is being injected. Consequently, the present methods and system may comprise the use of one or more separation units.
[0085] In particular embodiments, it may be useful to remove some or all of the water present in the CO2 stream. While it may be useful for a "wet" CO2 stream to be introduced directly into a formation for improved recovery of certain deposits, including with respect to certain fossil fuels, if otherwise necessary, the water present in the CO2 stream (eg. the water formed during the combustion of a carbonaceous fuel and persisting through any other processing prior to injection) can be removed primarily as a liquid phase from a stream of cooled CO2. Such separation can be achieved by providing the CO2 flow (eg in a gaseous state) at a pressure that is less than the point at which the CO2 present in the gas mixture is liquefied when the gas mixture is cooled to the lowest temperature obtained with cooling means at room temperature. For example, the CO2 stream can be supplied at a pressure less than 7.38 MPa during the separation of secondary components from it. An even lower pressure may be required if cooling means at a temperature in the low ambient range or substantially lower than ambient are used. This allows the separation of water as a liquid. In some embodiments, the pressure can be substantially the same as the pressure at the turbine outlet. A "dry" CO2 stream after water separation may comprise water vapor in an amount less than 1.5% on a molar basis, less than 1% on a molar basis, or less than 0.5 % on a molar basis. If desired, further drying can be applied so that the CO2 stream is completely or substantially free of water. For example, low concentrations of water can be removed by desiccant dryers or other means that may be appropriate in light of the present disclosure.
[0086] Other minor components that can be removed from the CO2 stream include, for example, SO2, SO3, HCl, NO, NO2, Hg, O2, N2 and Ar. These minor components of the CO2 stream can all be removed from a cooled CO2 stream using appropriate methods, such as those defined in US Patent Application Publication no. 2008/0226515 and European Patent Applications in EP1952874 and EP1953486, all of which are incorporated herein by reference in their entirety. In specific embodiments, various minor components can be removed by the following methods: SO2 and SO3 can be converted 100% to sulfuric acid; >95% of NO and NO2 can be converted to nitric acid; Excess O2 can be separated as an enriched stream for optional recycling to the combustor; and inert gases (eg N2 and Ar) can be vented at low pressure to atmosphere.
[0087] In modalities where the flux of the combustion product is cooled to facilitate the removal of one or more components from it, it may be useful to reheat the flux before injecting into the formation. As described above, one or more heat exchangers can be used to cool the combustion product stream. If desired, the stream containing CO2 can be passed back through the same heat exchanger(s) to capture the heat extraction previously from the combustion product stream.
[0088] If desired, the CO2 stream can be supplied for injection or recycling into the combustor as a circulating fluid in a substantially purified form. Specifically, a purified CO2 stream can have a CO2 concentration of at least about 95%/mol, at least about 97%/mol, at least about 98.5%/mol, at least about 99%/ mol or at least about 99.8%/mol. Furthermore, the stream containing CO2 can be supplied at a desired pressure for injection into a formation, introduced into a pipeline, and/or introduced into the combustor. It may be particularly useful for the stream containing CO2 to have an injection pressure (ie the pressure of the stream containing CO2 at the injection point in the formation - such as leaving the well and entering the formation) that is at a minimum level. For example, the CO2 containing stream can have an injection pressure of at least about 1.5 MPa, at least about 2 MPa, at least about 3 MPa, at least about 4 MPa, at least about 5 MPa at least about 6 MPa, at least about 7 MPa, at least about 7.5 MPa, at least about 8 MPa, at least about 9 MPa, at least about 10 MPa, at least about 11 MPa, or at least about 12 MPa. In other embodiments, the CO2 containing stream may have a pressure from the ambient of about 30 MPa. Such pressures can likewise apply to any portion of the CO2 stream that is recycled back into the combustor and/or is introduced into a pipeline.
[0089] In certain embodiments, the flux containing CO2 can be characterized in relation to its viscosity and/or density. Preferably, the stream containing CO2 will have an injection pressure that will be close to or above the minimum miscibility pressure (MMP) of the formation (and its deposit of combustible material). Consequently, the density and viscosity of a stream containing CO2 according to the invention can be a function of the specific well MMP, which can be a known value. For example, it is shown in North Sea reservoirs that CO2 used in EOR should have a density of 570 kg/m3 to 800 kg/m3 and a viscosity of 0.04 MPa s to 0.07 MPa s. If desired. The invention may encompass the use of additives to change the density and/or viscosity of the CO2 containing stream.
[0090] In preferred embodiments, a CO2 stream produced from a combustion system or method can be injected into a deposit formation without the need for separation of any non-CO2 components and/or CO2 stream compression. Consequently, in modalities related to surface combustion, the CO2 stream can be injected into a formation after combustion only, after combustion and expansion for power generation, after combustion and cooling, or after combustion, expansion and cooling. Preferably, in embodiments relating to surface combustion, at least one expansion step is included to provide energy output, particularly in embodiments where some level of pressure reduction is useful prior to injection into the formation.
[0091] In some embodiments, direct injection of CO2 stream into a formation may be particularly desirable. Direct injection can be characterized as stream injection of the combustion product containing CO2 into the formation without any other intermediate steps as otherwise described in this document (eg without expansion, cooling or separating components from the stream). Direct injection can include transporting the CO2 stream from the combustor to a separate pipeline that delivers the CO2 stream to an injection site or from the combustor through a pipeline that is a dedicated component of the system and method. The release to an injection head component through existing oil well components, natural gas well components, or similar may also be considered direct injection of CO2 stream in accordance with the invention.
[0092] It may be particularly beneficial for a power generation facility, as described above, that produces CO2 for enhanced formation deposit recovery to be located substantially close to the formation where the O2 will be injected. Such proximity can reduce or eliminate the need to transfer excess CO2. For example, in embodiments where the formation deposit for recovery is a fossil fuel, it may be beneficial for the energy production facility to be located in or near the field including the well or wells from which the fossil fuel is being recovered. Preferably, the energy production facility can be located very close to where the CO2 will be injected to improve fossil fuel recovery. In this way, the use of pipelines, tank trucks, and the like can be reduced or completely eliminated. In particular, the present CO2 production system may include piping sections that are in fluid connection with the remaining components of the combustion system so that the CO2 produced by combustion is specifically directed to the injection well through the pipe without connections that allow the entry of CO2 from a source that is external to the system of the invention.
[0093] In some embodiments, the energy production may be close enough to the site where the produced CO2 is injected so that any piping that was used to direct the produced CO2 to the injection site has an overall length less than about 50 km, less than about 40 km, less than about 30 km, less than about 20 km, less than about 10 km, less than about 5 km, less than about 2 km, less than about 1 km, less than about 0.5 km, less than about 0.25 km or less than about 0.1 km. In some embodiments, any transmission piping associated with the transmission of CO2 from the power generation facility to the injection site can be described as having a length close to zero. This can particularly mean pipes that have an overall length of less than about 0.5 km, less than about 0.25 km, or less than about 0.1 km. Such distances can be considered a "close to zero" distance in accordance with the present invention since the Co2 transmission pipes have a length measured in the hundreds of kilometers. Thus, in comparison, the values indicated above can be considered to be relatively close to zero. Furthermore, the ability to supply the CO2 production facility in such close proximity to the injection site is not a matter of mere optimization that can be achieved without real effort. Of course, known CO2 sources are typically not amenable to construction at specific sites at specific distances from where an injection site can be located. This limitation is because the technique has typically required large lengths of pipelines and/or means to transport CO2 the distances necessary to reach the fossil fuel deposit where improved recovery methods are needed.
[0094] This advantage of the present invention is particularly conceived by the ability to provide a CO2 production system that is fully transportable due to, but not limited to, its small size and modular design. A fully transportable system in accordance with the present invention may be a surface production facility or a downhole combustion system which is formed from components that can be assembled to form an operable facility in a relatively short time and whenever desired, can be disassembled in a relatively short time so that the full complement of components can be transported to a different location (eg, by road, rail or other suitable vehicle) and reassembled in a relatively short time. Thus, the system or apparatus can be described as being modular in nature so as to allow the system to be reconfigured from a transport mode to an operating mode. As used in relation to these modalities, a relatively short time can be defined to mean a total assembly time from separate components to operable installation (eg produce CO2) or a total reconfiguration time of less than 56 days, less than 49 days, less than 42 days, less than 35 days, less than 28 days, less than 21 days, less than 14 days, less than 10 days, less than 7 days, less than than 5 days or less than 2 days. Equal time periods may apply to disassembly of an operable installation for separate components. Such transportable systems may include energy production components as described herein or may be substantially limited to the compounds and associated components required for the production of CO2. Furthermore, such a transportable system can be compact enough to be *crib-mounted. In this way, the CO2 production system can be transported to a specific injection well and attached substantially directly to the wellhead for direct injection of the CO2 produced into the well. The CO2 production process is thus compact and can be built into a shape for disassembly, transport to a new recovery site, and reassemble at the lowest possible cost. This likewise can work to eliminate the cost of a CO2 pipeline.
[0095] In addition to surface combustion, as described above, the present invention also encompasses modalities in which combustion is performed at a subsurface location. By the term “subsurface” it is meant that the actual combustion of fuel to produce CO2 is carried out in a physical location that is below ground level. In some arrangements, the combustor may be located only a few meters below ground level. In other embodiments, the combustor can be located above about 10 m, above about 100 m, above about 500 m, above about 1,000 m, above about 1,500 m, above about 2,000 m, above about 5,000 m, or above about 10,000 m below ground level. In other embodiments, the combustor can be located at least about 1 m, at least about 10 m, at least about 25 m, at least about 50 m, at least about 100 m, at least about 250 m , at least about 500 m, or at least about 1,000 m below ground level. In still other modes, the combustor can be located about 1 m to about 5,000 m, about 5 m to about 4,000 m, about 10 m to about 3,000 m, or about 25 m to about 2,000 m below the level of the ground. In accordance with this aspect of the invention, the combustor can be characterized as being located at the bottom of the well (particularly in relation to fossil fuel formations or other formations where a well can be drilled to recover the deposit), as being located within the formation. from which enhanced recovery is desired, as being located above the warehouse for which enhanced recovery is desired, as being located below the warehouse for which enhanced recovery is desired, or as being located apart from the warehouse for the which enhanced recovery is desired (ie, on a common horizontal plane with the warehouse).
[0096] When downhole combustion is used, it can be particularly beneficial in completely eliminating the pre-injection energy production system in which a working fluid is used, such as to generate electricity. In this way, the methods and systems of the invention can be effectively condensed in as little as a combustor and any piping needed to release the combustion materials (and any additionally desired enhanced recovery components - eg water for steam generation) to the bottom from the well to the inlet end of the combustor. Thus, combustion can be carried out to produce CO2 (and optionally steam or other products useful for improved recovery of certain deposits), which passes directly from the exit end of the combustor into the formation for improved recovery of particular deposits, as described. in this document. As discussed in more detail below, the CO2 produced can be combined with the deposit that is recovered from formation in the recovery stream. If desired, specifically produced CO2, or part of the entire recovery stream, can be used to generate energy in the same way as described above. In these embodiments, the energy production components of systems and methods can be physically separated from the combustor (i.e., the combustor being located at the bottom of the well and the energy production turbine(s) and similar components or being located above ground). Even in such embodiments, however, the combustor and power producing components can be described as being in fluid communication. Specifically, the flux of combustion product leaving the exit end of the combustor passes into the formation, mixes with or otherwise facilitates the recovery of the deposit, and is included in the recovery flow from the formation that can be passed through the energy producing components or separated into one or more portions before being passed through the energy producing components.
[0097] If surface combustion or downhole combustion is employed, the present invention may refer to improved recovery of a variety of materials. In specific embodiments, the methods and systems of the invention can be used to improve the recovery of fossil fuels. In particularly preferred embodiments, the invention may particularly relate to improved recovery of fossil fuels in a fluid form. In specific embodiments, a fluid shape can mean a shape that is flowable at standard temperature and pressure. The fossil fuel can be in substantially a fluid form while held within its formation (or reservoir), such as in the case of a sufficiently low viscosity crude oil or natural gas. Fossil fuel can also be characterized as being in a fluid form after contact with CO2 and/or any steam or other heating and/or dilution material that can be used, such as in the case of bitumen, tar sands, petroleum shale or similar.
[0098] The enhanced recovery methods of the invention may include releasing a stream containing CO2 to a formation including a deposit for recovery. Although the CO2 containing stream may include one or more other components, it is desirable for the CO2 containing stream to comprise at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 95%, at least about 98%, or at least about 99% by weight CO2 based on total flux weight. In other embodiments, the CO 2 -containing flux can comprise about 50% to about 100, about 60% to about 98%, about 70% to about 97%, or about 75% to about 95%. % by weight of CO2. As indicated above, the CO2 in the CO2 containing stream can be in the form of a supercritical fluid or a gas. In some embodiments, the flow containing CO2 can be characterized as consisting of CO2. In other embodiments, the flow containing CO2 can be characterized as consisting essentially of CO2. In such embodiments, "consisting essentially of" can specifically mean any of the following: the CO2 containing stream comprises less than 2% by weight of any non-CO2 components; the stream containing CO2 is expressly free of any other material that is typically recognized as a fracture fluid; the stream containing CO2 is expressly free of any solid materials to maintain an open induced hydraulic fracture (proppant); or the flux containing CO2 is expressly free of any surfactants.
[0099] As can be seen from the above, the present invention can specifically provide methods for enhanced recovery of fossil fuel reserves. In various embodiments, the methods can be applied to any formation that may contain one or more of methane, other light hydrocarbon gases (eg C2 to C4 gases), oil of varying viscosities, bitumen, tar sands and petroleum shale . For example, a method according to the invention may comprise: combustion of a carbonaceous fuel to provide a flux of combustion product comprising CO2; and directing at least a portion of CO2 into a formation containing the fossil fuel for recovery. Furthermore, the method may comprise receiving a fluid stream from the formation comprising a fraction of fossil fuel from the formation and a fraction of CO2 injected into the formation. In other embodiments, at least a portion of the fossil fuel fraction recovered from the formation can be separated from the fluid flow. The separated fossil fuel fraction may comprise light oils, heavy oils, light gases, or high viscosity combustible materials (eg bitumen, tar sands and petroleum shale). A plurality of separations can be applied to obtain from the fluid flow all marketable products, and such separations can result in the isolation of non-hydrocarbon materials, including CO2. In other embodiments, at least a portion of the recovered fluid stream can be recycled back to the combustion method. Specifically, the recycled stream can comprise CO2 and/or a recovered fossil fuel content (eg a light gas fraction). Furthermore, in modalities for recovering mixed hydrocarbon products (eg including a gas fraction and a liquid oil fraction), it may be beneficial to separate the liquid fraction for marketing. The remaining gas fraction (including any impurities and CO2) can be introduced directly to the combustor as all or part of the combustion fuel. Preferably, the recovered fossil fuel content can be sufficient to fully fuel the combustion process without requiring the introduction of external fuel sources. In other embodiments, the portion of recovered fossil fuel recycled within the system can be used to supplement an external fuel source. Such methods can similarly be applied to recover other types of formation deposits.
[00100] In other embodiments, the present invention can provide systems to provide CO2 for recovering a fossil fuel from a formation. For example, a system in accordance with the invention may comprise the following: a combustor configured to receive a carbonaceous fuel and having at least one combustion stage that burns the fuel to provide a combustion product stream comprising CO2 and one or more components to direct at least a portion of CO2 into the formation. The system may also comprise one or more power generation components, such as electricity generation turbine components, which may be in fluid connection with the combustor and/or may be positioned for power generation using a material flow component. recovered fuel. The system may further comprise one or more components for receiving a fluid flow from the formation comprising a fraction of fossil fuel from the formation and a fraction of CO2 directed into the formation. The system may further comprise one or more components for separating at least a portion of the fossil fuel fraction recovered from the fluid flow and/or one or more components for recycling at least a portion of the fluid flow back into the combustor. . Such systems can similarly be adapted for recovery from other types of formation deposits.
[00101] In some embodiments, the invention may refer to the use of CO2 in the enhanced recovery of a fossil fuel through a fracturing process. Fracturing can be particularly useful in the improved recovery of hydrocarbon gases, such as coal beds and hydrocarbon-carrying formations, containing shale, which typically contain methane (CH4) and small amounts of other light hydrocarbon gases.
[00102] When a treatment fluid containing CO2 is injected into an appropriate formation (as described above, for example) at a pressure above the fracture pressure of the formation, the formations can be effectively fractured to stimulate methane production and other hydrocarbon gases. Fracturing relieves stresses in the formation, dissolves trapped gases, and creates pore spaces and channels for gas flow from the formation into a well. Furthermore, due to preferential displacement of absorbed or cross-linked methane by CO2, more methane is evolved from the treatment than might otherwise occur with other fracturing treatments or with the use of other gases. The use of CO2 also provides the longer term improvement in total gas production due to the ability of O2 to displace methane. If enough methane is displaced in the localized area of the fracture face surrounding the well, the pressure in the formation may also drop low enough that it fails below the critical desorption pressure of methane within the formation, which can result in spontaneous desorption and in the significant production of methane.
[00103] Fracturing according to the invention can be used with any formation where hydrocarbon production, particularly gaseous hydrocarbon production, is sufficiently impeded by the low formation pressures and/or low permeability of the formation (i.e., a formation "firm"). Formations (eg, shale formations, coal beds, and the like) that have sufficiently low permeabilities to make fracturing a favorable method of improved recovery may include those that have a permeability of less than about 10 mD, less than than about 5 mD, less than about 1 mD, or less than about 0.5 mD).
[00104] A method of fracturing according to the present invention may comprise introducing a stream containing CO2 (such as through a well or other injection well) into a formation at a pressure that is above the fracture pressure of the formation. Fracture methods may particularly comprise the use of a surface combustor. Consequently, the stream containing CO2 can essentially be the stream of combustion product leaving the combustor. In other embodiments, flow containing CO2 can be the flow leaving the turbine or other energy producing components. In still other modalities, the flow containing CO2 can be the flow that leaves the components used in any steps of the separation process that can be carried out. Furthermore, additional fracture materials can be added to the CO2 containing stream at any point after combustion and immediately prior to introduction into the fracture (which may include combinations taking place within the wellbore itself). Such additional components include, but are not limited to solid materials to maintain an open induced hydraulic fracture (proppant), surfactants (eg, aliphatic or oxygen-containing hydrocarbon polymers, hydrofluoropolymers, small molecules partially or fully fluorinated with weights molecular substances up to 400 g per mol, perfluoroethers, neutral surfactants, charged surfactants, zwitterionic surfactants, fatty acid esters and/or surfactants that give rise to viscoelastic behavior), gelling agents, or water (including brines). The CO2 containing flux can also be characterized as being expressly free of any or all of the above components or any other components that might typically be recognized as being useful in a fracturing fluid. Furthermore, the stream containing CO2 can be introduced into the formation simultaneously, before, after, or sequentially with water and/or other fluid or fracture material.
[00105] Carbon dioxide can be particularly useful to displace methane from crosslinking structures such as methane hydrates and methane clathrate, as well as to displace adsorbed methane from surfaces, pore spaces, interstices and veins of a formation. Other gases, such as nitrogen or air, typically do not demonstrate a similar preferential tendency to displace adsorbed or cross-linked methane. Coal beds and gas hydrates, in particular, show preferential adsorption of or substitution by CO2 compared to methane.
[00106] Due to the tendency of CO2 to displace methane from reticulation structures and displace adsorbed methane from surfaces, pore spaces, interstices and veins of a formation, CO2 produced according to the present invention can also be specifically used to achieve these functions in the absence of fracture. In other words, the stream containing CO2 can be introduced into a formation, such as at a pressure below the fracture pressure of the formation, but at a pressure sufficient to introduce veins or breaks in the formation or at a pressure sufficient to introduce at least one portion of the pores of the formation in order to displace adsorbed hydrocarbon gases or otherwise facilitate the removal of hydrocarbon gases from the formation. This feature can be beneficial for the recovery of natural gas from coal beds, surface coal seams (particularly those that are deep and/or have one or both economic and technical production problems), and formation of shale gases where natural gas or other short-chain hydrocarbon gases are associated with the solid materials and are preferably displaced by CO2. Although CO2 in a frac method is preferably produced by surface combustion to allow the optional inclusion of other materials, CO2 for a pure gas recovery method without fracturing can be produced by surface combustion or in a combustor at the bottom of the pit. The stream containing CO2 that is injected into such formations through a first well (ie, an injection well) displaces the hydrocarbon gases therefrom, combines at least partially with the displaced hydrocarbon gases and facilitates the recovery of hydrocarbon gases from the formation, such as through the injection well or one or more recovery wells. The recovered hydrocarbon gases optionally can be treated as further described below.
[00107] In addition to the improved recovery of hydrocarbon gases, the methods of the invention can also be used both to form and to recover a combustible material. For example, CO2 will chemically react with coal, particularly at elevated temperatures and pressures, to produce CO and H2 (as well as water). Thus, CO2 produced in accordance with the present invention can be introduced into a coal formation in order to chemically react with the coal and form CO and H2, which can be recovered as otherwise discussed herein and used as combustible materials - for example, in the production of synthesis gas (syngas). In certain embodiments, multiple functions can be performed where the injection of CO2 into the coal formation can shift to recover any hydrocarbon gases therein, and/or react with the coal to form CO and H2 for recovery, and/or sequester at least a portion of CO2 within the coal formation.
[00108] The CO2 produced according to the present invention can also be useful to improve the recovery of liquid combustible materials (eg crude oil) and even highly viscous combustible materials (eg bitumen, tar sands and petroleum shale) . The use of a stream containing CO2 in relation to such highly viscous and/or liquid combustible materials can be effective in improving their recovery through a variety of methods, such as one or both of increasing formation pressure and altering nature. of the combustible material (eg, reducing its viscosity).
[00109] The displacement of oil by CO2 injection may depend on the phase behavior of the CO2 and crude mixtures, which may depend on a variety of factors such as reservoir temperature, reservoir pressure, and crude oil composition. While not wanting to be bound by theory, it is believed that mechanisms that facilitate crude oil displacement may include oil swelling, viscosity reduction, and complete miscibility of CO2 and crude oil. The methods of the present invention can provide one or any combination of such mechanisms for improved recovery of highly viscous oil and hydrocarbons from a formation. Although the discussion below generally discusses the removal of liquid hydrocarbons with respect to oil (or crude oil), it is understood that such disclosure may refer to improved recovery of oil from a wide range of viscosities and may also refer to recovery improved from other highly viscous hydrocarbons - eg bitumen, tar sands, similar oil shale.
[00110] When CO2 is injected into an oil reservoir, it can become mutually soluble with the residual crude oil as the light hydrocarbons from the oil dissolve in the CO2, and the CO2 dissolve in the oil. The extent of such mutual dissolution may increase as the density of CO2 increases which may particularly favor the supply of CO2 in a compressed (ie pressurized) form. Mutual dissolution may also be greater in formations where the oil contains a significant volume of "light" hydrocarbons (ie, lower carbon). When the injected CO2 and residual oil are miscible, the physical forces that hold the two phases apart (interfacial tension) effectively disappear. This allows the CO2 to displace oil from the pores of the rock, pushing it into a production well. As CO2 dissolves in the oil it swells the oil and reduces the viscosity of the oil, which also helps to improve the efficiency of the displacement process.
[00111] Since the minimum pressure required to achieve mutual dissolution of oil and CO2 can be a factor of reservoir temperature, reservoir pressure, flow pressure, and oil density (ie, the relative fraction of light hydrocarbons ), the minimum pressure required to achieve oil/CO2 miscibility may vary. Consequently, in addition to controlling the nature of the injected CO2 stream (ie, temperature, pressure, and optional additives such as steam), the invention may comprise additional treatments in addition to CO2 injection. For example, before, after, or simultaneously with CO2 injection, the invention may also comprise injection of water into the formation, which may be particularly beneficial in increasing reservoir pressure. More specifically, the invention may comprise alternative injection of CO2 stream with volumes of water. This technique can be referred to as alternating water gas floods (or "WAG"). Such a method can be useful to alleviate any tendency for high-viscosity CO2 to slip past the displaced oil. Other similar techniques can also be encompassed by the present invention.
[00112] By way of example only, a CO2 injection method for improved oil recovery according to the invention can be carried out as follows. Firstly, combustion can be carried out as already described herein to produce a stream containing CO2 (preferably comprising supercritical CO2). Combustion can be carried out above ground or at the bottom of the well, and any intermediate steps deemed appropriate under the specific circumstances of the formation that is simulated can be carried out (for example, expansion for energy production and/or separation of any components from flow that are not desired for injection). Preferably, if surface combustion is used, the combustion system can be located significantly close to the injection well and/or oil field where the CO2 containing stream is to be used. CO2 can particularly be supplied for injection at an injection pressure as otherwise described in this document.
[00113] Then, the flow containing CO2 leaving the combustor (or other system components as desired) can be directed to one or more injection wells strategically placed within a pattern to optimize the sand sweep of the reservoir. This can be via a relatively short transfer line as discussed above. When downhole combustion is used, directing the flow containing CO2 may comprise simply emitting the flow containing CO2 from the combustor and directly into the formation, such as through perforations in a well casing or through a face of open rock. The injected CO2 enters the reservoir and moves through the pore spaces of the formation rock. As CO2 moves through the reservoir and encounters crude oil deposits, it can become miscible with the oil and form a bank of concentrated oil that is swept towards separate production well(s)( s) - which may include the injection well in some modalities. In other words, the movement of the flow containing CO2 through the reservoir improves the movement of oil out of the formation and into the production well(s). This may proceed due to the mutual solubility phenomenon described above and because the formation still demonstrates sufficient pressure to "push" the oil/CO2 combination (which now has a reduced viscosity and/or density relative to oil alone) into the wells. open production (which have a lower density in relation to the formation itself). The movement of oil to the production well(s) can also arise from an increase in the pressure of the formation that arises from the injection of CO2 into it (and/or any other repressurization materials that may be injected - for example, water).
[00114] In the production well(s), oil (typically as a mixture of oil, CO2, water and possibly hydrocarbon gases) is released to the surface (which typically may include active pumping) for processing , as described below. The stream containing CO2 can be injected into a number of injection wells, and the pattern of the injector wells and producer wells can change over time. Desirable patterns can be determined based on recognized engineering models, such as computer simulations that model reservoir behavior based on different design scenarios.
[00115] Although the use of CO2 in the stimulation of oil and gas wells has been previously known, it is well recognized that CO2 EOR is a capital-intensive realization with the largest single project cost typically being the cost of acquiring Co2 for injection, particularly at the required pressure and purity. It has been estimated that in EOR procedures, the total CO2 costs (both acquisition cost and recycling costs) can add up to 25 to 50 percent of the cost per barrel of oil produced. The present invention can overcome such limitations by providing a continuous source of CO2 that is formed in proximity to the injection sites and can even be formed at the bottom of the well to further eliminate CO2 transport costs. Furthermore, CO2 production costs can be effectively offset by producing energy through a pre-injection cycle as described above and further by producing energy using the production flow in some embodiments. Furthermore, as further described in this document, combustion fuel costs can be significantly offset by using a fraction of the combustible materials recovered in the enhanced recovery process (including liquid and gaseous combustible materials).
[00116] In addition to the high capital costs of a CO2 supply/injection/recycling scheme, the initial CO2 injection volume typically must be purchased well before the start of incremental production. Consequently, the return on investment for CO2 EOR tends to be low, with only a gradual, long-term disbursement. Given the significant upfront investment in wells, recycling equipment and CO2, the time delay in obtaining an incremental oil production response, and the potential risk of unexpected geological heterogeneity significantly reducing the expected CO2 EOR response so far is considered. a risky investment by many operators, particularly in areas and reservoirs where it has not been implemented previously. Furthermore, it was previously understood that oil reservoirs with higher capital cost requirements and less favorable ratios of injected CO2 to the incremental oil produced will not obtain an economically justifiable return on investment without improved technology and/or tax/fee incentives for store CO2. Again, the present invention overcomes these drawbacks and produces CO2 based on economically justifiable and yet advantageous improved recovery methods across a wide range of combustible material deposits and still other types of deposits.
[00117] As already indicated above, the methods and systems of the present invention may be particularly beneficial in light of the ability to position the combustor apparatus at the bottom of the well within the reservoir or formation. Such modalities can be particularly useful in EOR methods. More specifically, downhole combustor modalities can be highly advantageous for use with bitumen-containing formations, for use in tar sands, for use in oil shale extraction, and for use with heavy oil generally - i.e. oil having an American Petroleum Institute (API) gravity below about 20. In specific embodiments the methods and systems of the invention can be particularly used in oil-containing formations with an API gravity that is less than about 19, less than about 18, less than about 17, less than about 16, less than about 15, less than about 14, less than about 13, less than about 12, less than about 11, less than about 10, less than about 9, or less than about 8. An API gravity can be directly measured using a graduated hydrometer with API gravity units as detailed in ASTM D287. Alternatively, API gravity can be calculated from the density of the oil, which can be measured using either a hydrometer, as detailed in ASTM D1298, or with an oscillating U-tube method, as detailed in ASTM D4052. Density adjustments at different temperatures, soda lime glass expansion and contraction corrections, and meniscus corrections for opaque oils are detailed in the Petroleum Measurement Table details for the use specified in ASTM D1250. Specific gravity is then calculated from formula 1 below, and API gravity is calculated from formula 2 below.

[00118] The use of a downhole combustor in the improved recovery of combustible material deposits from a formation according to certain embodiments of the invention is illustrated in the flowchart of Figure 1. In particular, the Figure illustrates a cross section of a typical geological formation consisting of (top to bottom) a top 2 earth layer, a low porosity 3 rock layer (such as shale) that does not allow significant oil infiltration, a medium porosity 4 rock layer that may or may not allow oil infiltration, an oil-containing layer 5 (such as a sandstone or limestone) that has sufficient porosity to contain oil and possibly allow free flow of it to a lower pressure zone, and a layer of medium porosity rock 6. It is understood that such geological formation is exemplary only, and geological formations that can benefit from the methods of the present invention may be more or less layers with a the variety of different configuration including layer crossing. Furthermore, the discussion regarding an oil-containing layer should not be seen as limiting downhole combustion to such formations alone.
[00119] An injection well 100 is shown penetrating the various layers of the geological formation including the oil-containing layer 5. Although a single injection well is shown, it is understood that a plurality of injection wells may be used. Furthermore, the injection well can be a pre-existing downhole that is modified, if necessary, to accommodate the downhole combustor (or its products) or it can be a purpose-built drill hole. The illustrated injection well 100 includes a conductor casing 101, a surface casing 102, and a production casing 103, Ada one of which can be cemented into position. Internal to the production liner is a work pipe 104 which is used to release the combustion materials. In some embodiments, the working piping may be absent, and release of combustion materials may proceed through the production liner. In cases where a well is formed expressly for the purpose of combustion at the bottom of the well, casing combinations may vary or be essentially absent. For example, the injection well may simply comprise a conductor, a surface casing, and an open well hole extending below the lower edge of the surface casing. In the illustrated embodiment, an injection seal cap 110 for use as a pressure seal is provided near the lower end of the working pipe 104 to isolate the upper portion of the well from the combustion zone 112 below.
Within the combustion zone 112 is a combustor 300, such as a perspiration cooled combustor as otherwise described herein. The combustor is geographically aligned with the oil containing layer (or formation) relatively low in the formation. The exact location within the formation may vary - for example, high in the formation to favor downward movement of injected materials or low in the formation to favor upward permeation of injected materials - and such location may depend on the exact nature of the materials injected and the exact nature of the deposit to be recovered from the formation). In particular embodiments, it may be desirable to use one or more non-vertical wells as an injection well. For example, the injection well can include one or more horizontal sections from which stream containing CO2 can be injected into the formation. The injection well may likewise include one or a plurality of branches which may be any vertical, horizontal or diagonal with respect to the ground level surface. In other embodiments, the combustor or components that direct the flow containing CO2 may be located on rails or pulleys or may use other mechanisms to allow it to move in all potential directions. Valves that control the flow to various portions of the combustor can also be used to control the direction of CO2 flow.
[00121] A combustion fuel source 10 delivers downhole combustion fuel to the combustor 300, such as through an associated piping or otherwise appropriate release means. As further described below, combustion fuel may be a fraction of combustible material recovered from deposit formation. An oxidant source 20 (which is an air separation unit supplying O2 by way of example in this embodiment) supplies O2 (preferably in a substantially purified form as described above) from the bottom of the well to the combustor, such as through an associated tubing or otherwise appropriate release means. A stream of CO2 30 is also provided to pass through the combustor. In the illustrated embodiment, the CO2 stream converges with the O2 stream from the oxygen source in mixer 25. Alternatively, the CO2 stream can go directly to the combustor in a separate release line. Furthermore, an additional or different mixing device can be used to combine the fuel, oxygen, and CO2 prior to passage into the combustor. In embodiments where CO2 from combustion is significantly sequestered in the injected formation or is not recycled to the combustion method, the CO2 flux may be absent. In the illustrated embodiment, the combustion system further includes a quench fluid source 40 which can specifically supply water, a different quench fluid (including CO2), or quench fluid mixtures to the combustor through an associated piping or otherwise appropriate release means. Coarse coolant can be specifically released to the combustor as a perspiration coolant. In addition, the CO2 stream can be released to the combustor through the source of quench coolant (particularly when CO2 might be desired for use as a perspiration coolant).
[00122] When the combination of feeds (i.e., O2, water, CO2 and fuel) is released into the combustor, combustion can proceed, and the combustion products exiting the combustor can include one or more of heat, steam, CO2, and reaction by-products as otherwise discussed in this document. The combustor can be described as having an entry zone, into which fuel and other materials are released, and an exit zone from which the flow of combustion products is produced. As seen in Figure 1, production casing 103 may include one or more perforations 105 which may be located significantly in the area of combustor 300 or may be spaced apart at various locations corresponding to the oil production formation. Such perforations can provide passage of combustion product flow out of the well and into the oil-containing formation. In other embodiments, the production coating 103 may be absent, at least within the oil production formation, and the flux of combustion product may readily flow through the formation pores.
[00123] The propagation of combustion products through production formation facilitates the recovery of formation deposits (eg oil) through one or more production wells 200. Such propagation of combustion products and formation deposits is illustrated by the block arrows in Figure 1. The unfilled arrows represent the combustion product entering the formation. The darker arrows successively represent formation deposits (eg oil) that are miscible with CO2 and, now having a reduced viscosity (and optionally increased temperature from steam treatment and/or increased pressure), proceed into the production well. In some embodiments, injection well 100 may be configured to inject combustion product stream into a first zone within a production formation and receive formation deposits produced in a second zone within the production formation. For example, injection of combustion product stream may proceed from the production liner to below the sealing cap 110, and deposits can enter the production liner above the sealing cap through one or more additional perforations (not shown), and the recovered deposits can flow through an annular space between the production liner 103 and the work tubing 104.
[00124] The separate production well 200 shown in Figure 1 includes a conductor casing 201, a surface casing 202 and a production casing 203, each of which can be cemented into position. In this embodiment, the production casing extends only a short distance below the lower end of the surface casing, and the remaining portion of the well below it is illustrated as simply an open pit 206. In other embodiments, the production casing it may extend further down into the well, and the open well may actually include a casing or casing that may be perforated or otherwise porous to allow the passage of deposits produced within the well. Internal to the production liner is a production line 204 which is used to release the recovered deposits to the surface, and the production line is surrounded near the lower end of it with a production sealing cap 210.
[00125] The recovered deposit stream 250 released to the surface of the production well 200 may undergo one or more processing steps. For example, the recovered deposit stream can be passed through an expander 320 to reduce the flow pressure. The optionally reduced pressure stream may pass through a separation unit 330, such as separating a heavy oil stream 332 from a light gas stream 334. The light gas stream may proceed through a gas separator 340 which can insulate a hydrocarbon gas stream 342 of any CO2 (and/or impurities - eg H2S) combined with the stream from the recovered deposit. The expanded CO2 344 flow can optionally proceed through a power generation turbine 350 to produce electricity (E), and the expanded CO2 flow 30 can proceed to the mixer 25 to combine with the CO2 flow for reinjection into the well. injection 100. In alternative embodiments any of the streams 250, 332, 334, 342, and 344 may be introduced directly into the combustion system, particularly if any of the intermediate pressure adjustment, separation, or power generation components are not required. or desired.
[00126] In some modalities, instead of separating the light gases, such component can remain in combination with the CO2 flow for introduction into the combustor. In this way, the requirement for a separate fuel source for the combustor can be partially or completely eliminated. In effect, a method according to the invention can thus produce a crude oil product for trade, and any light gases produced can be used as the fuel source for the combustor to form more CO2 to continue the EOR operation. . Furthermore, the gas separation step can still take place, and any separated hydrocarbon gases can be released into the combustor as the fuel source. Other modalities related to the separation of components from the product recovery fluid are otherwise discussed herein.
[00127] In some embodiments, it may be useful to specifically adjust the ratio of oxidant to CO2 that is introduced into the combustor. For example, the amount of oxidant introduced into the combustor can be less than about 50% by weight of the amount of O2 introduced into the combustor. In other embodiments, the amount of oxidant introduced into the combustor can be less than about 45%, less than about 40%, less than about 35%, or less than about 30% by weight of the amount of CO2 introduced into the combustor. In specific embodiments, the amount of oxidizer introduced into the combustor can be about 10% to about 50%, about 10% to about 45%, about 12% to about 40%, about 12% to about 40%. about 35%, or about 15% to 30% wax by weight of the amount of CO2 introduced into the combustor.
[00128] In certain embodiments, it may be particularly desirable to produce a significant amount of steam as part of the combustion process. Specifically, water can be added to the combustion cycle (eg as a quench coolant in the combustor) and can be particularly introduced into the combustor as a perspiration coolant. Thus, in addition to CO2, the combustion process can also provide a relatively large volume of steam. In certain modalities, the vapor fraction may be less than about 50%, less than about 40%, less than about 30%, less than about 20%, less than about 10% or less than about 5% of the combustion flow on a mass-to-mass basis. If desired, however (such as a thermal EOR process), the vapor fraction can be greater than 50% by mass of the combustion product stream.
[00129] In advantageous embodiments, the invention can be characterized in relation to the use of the bottom of the combustor with an excess of oxidant (for example, O2 or air). In specific embodiments, the amount of O2 that is supplied in excess of the stoichiometric content required for combustion of the fuel is at least about 0.1%, at least about 0.2%, at least about 0.25% , at least about 0.5% or at least about 1.0% on a molar basis. In other embodiments, the stoichiometric excess of O2 above the amount required for fuel combustion is about 0.1% to 5%, about 0.15% to about 4%, about 0.2% to about 3 %, or about 0.25% to about 2.5% on a molar basis. The amount of air supplied in excess of the stoichiometric content required for fuel combustion can be up to about 40 times excess. Providing such a stoichiometric excess can be useful to ensure full combustion of the carbonaceous fuel (which has the same characteristics as described above, with the ability to directly accept the enhanced recovery exhaust gas produced. This is desirable. because it can substantially or completely eliminate the production of carbon (i.e., soot), which can substantially plug the formation.For example, providing a large excess of oxidant can be effective in oxidizing coal to produce carbon monoxide (CO). In particular embodiments, carbon production can be limited so that the flux of combustion product comprises less than about 2%, less than about 1.5%, less than about 1%, less than about 0.5%, less than about 0.25%, or less than about 0.1% by weight of particulate carbon (or soot).
[00130] The provision of an excess of oxidant (particularly O2) is unexpected compared to an oil or natural gas as such wells typically require that any O2 present be strictly set at a very low level to avoid algal growth problems or sulfur deposition. In present combustion systems and methods, excess O2 is supplied as part of a high temperature gas stream. Under these conditions described herein, any excess O2 that remains after combustion can be effectively removed by side reactions with hydrocarbons in the reservoir. For example, the following reactions may occur under these conditions.Coal (CHx) + O2 = CO + 0.5XH2O Formula 3 2CO + O2 = 2CO2 Formula 4 CO2 + C = 2CO Formula 5 CO + H2O - CO2 + H2 Formula 6 H2 + O2 = H2O Formula 7 Oil (CH2)x + O2 = CO + XH2O Formula 8
[00131] It is expected that the reactions of formulas 4 to 7 may likewise follow the reaction of formula 8.
[00132] In addition to the above, the use of a downhole combustor with water flow injected with transpiration can be particularly advantageous to control the temperature of the enhanced recovery fluid flow. More specifically, the water content (and optionally the CO2 flow) can be adjusted as needed to directly cool the combustion product stream to a user-designated controlled temperature that can be set for maximum oil recovery in the particular reservoir. For example, combustion product flow temperatures can be controlled in the range of about 100°C to about 1800°C or any of the other ranges otherwise disclosed herein.
[00133] Although downhole combustion has been discussed earlier in the art, such methods differ from the present invention because combustion in known systems does not include a location where sufficiently high temperatures and pressures can be obtained to facilitate the combustion of still contaminated fuels , as discussed further below. Furthermore, known downhole combustion techniques have typically required the use of a solid support catalyst to prevent the production of soot from the face of the oil production formation. As already indicated above, the present invention can eliminate the requirement for such catalyst systems. If desired, however, in particular embodiments, combustion in accordance with the present invention (either surface combustion or downhole combustion) may also incorporate the use of a catalyst.
[00134] Particular modalities encompassing surface combustion are illustrated in Figure 2. As seen there, the general nature of the system and method is similar to downhole combustion in that a fuel source 10 supplies combustion fuel to the combustor 300 positioned on the surface, preferably substantially close to injection well 100. An oxygen source 20 (such as an air separation unit in this exemplary embodiment) delivers O2 (preferably in a substantially purified form, as described above) to the combustor. A source of working fluid 31 is also included to supply working fluid, such as a stream of CO2, for passage through the combustor. Optionally, another hard coolant, such as water, can be supplied to the combustor. Coarse coolant and/or working fluid can be specifically released to the combustor as a perspiration coolant by the discussion already given above. A blending device can be used to combine fuel, oxygen and CO2 prior to passage into the combustor.
[00135] By way of example, Figure 2 illustrates a cross section of a typical geological formation consisting of (from top to bottom) a top soil layer 2, a low porosity rock layer 3 (such as a shale), a fossil fuel reservoir and/or a coal bed layer 7 which includes methane and possibly other light hydrocarbons in it, and another medium porosity rock layer 6. Again, the current layering of geological strata may vary.
[00136] The injection well 100 is shown penetrating the various layers of the geological formation including the coal bed layer 7. Although a single injection well is shown, it is understood that a plurality of injection wells may be used. Furthermore, the injection well can be a pre-existing wellbore that is modified, if necessary, to facilitate the flow of CO2 or it can be a purpose-formed borehole. The illustrated injection well 100 includes a conductor casing 101, a surface casing 102 and a production casing 103, each of which can be cemented into position. Internal to the production casing is a work tubing 104 that includes a center tube 115 for injecting the stream containing CO2 into the well. In some embodiments, the working tubing may be absent, and the release of the stream containing CO2 may proceed through the center tube alone. In the illustrated embodiment, an injection seal cap 110 for use as a pressure seal is provided near the lower end of the working tubing 104 to isolate the upper portion of the well from the injection zone 113 below.
[00137] As illustrated in Figure 2, the production liner 103 may include one or more perforations 105, which may be spaced apart at various locations within the coal bed formation. Such perforations can provide passage of combustion product flow out of the well and into the coal bed. In other embodiments, the production liner 103 may be absent, at least within the coal bed formation, and the flux of combustion product may readily flow through pores on the face of the coal bed and/or through the veins in the bed. of coal.
[00138] In particular embodiments, it may be desirable to use one or more non-vertical walls as an injection well. For example, the injection well can include one or more diagonal or horizontal sections from which stream containing CO2 can be injected into the formation. The injection well may likewise include one or a plurality of branches which may be any vertical, horizontal or diagonal with respect to the ground level surface. The injection can again have potential or translational, axial and rotational motion.
[00139] In operation, the fuel source 10 provides combustion to the combustor 300, such as through an associated piping or otherwise appropriate release means, and such fuel may be a fraction of the combustible material recovered from the formation. of the deposit. An oxygen source 20 (such as an air separation unit) delivers O2 (preferably in a substantially pure form, as described above) to the combustor, such as through associated piping or otherwise appropriate release means. A stream of CO2 31 is also provided to pass through the combustor. In the illustrated embodiment, the CO2 stream preferably functions as a working fluid, and/or a quench fluid, and/or a transpiration fluid. If desired, a different working fluid and/or a quench fluid and/or a transpiration fluid (which may be the same or different) can be used, and separate sources for each flow can be provided. A blending device can be used to combine the fuel, oxygen and working fluid before passing into the combustor.
[00140] The combustor 300 includes an outlet from which flows a stream of combustion product, which can be described as a stream containing CO2. CO2 can be in any form as discussed above. Combustion product stream is introduced into a 350 turbine to produce electricity (E) and the output stream from the turbine is directed either to further processing or to the injection well. Processing components 375 may include one or more of a heat exchanger, a separation unit (for example, to remove water and trace impurities), a compressor, an expander, and a cooling unit. The stream containing CO2 - whether exiting the turbine or a processing computer - is at least partially directed into the well through the central tube 115 and enters the formation of the coal bed 7 through the perforations 105 in the production liner 103.
[00141] The propagation of the flow containing CO2 through the coal bed facilitates the recovery of formation deposits (eg methane) through one or more production wells 200. Such propagation of combustion products and formation deposits is illustrated by the block arrows in Figure 2. The unfilled arrows represent the flow containing CO2 entering the formation. The darker arrows successively represent formation deposits (eg methane) that mix with the CO2 and/or are simply displaced by the Co2 and proceed into the production well. In some embodiments, injection well 100 may be configured to inject combustion product stream into a first zone within a production formation and receive formation deposits produced in a second zone within the production formation. For example, injection of combustion product stream may proceed below sealing cap 110, and deposits may enter the production liner above the sealing cap through one or more additional perforations (not shown), and deposits recovered can flow through the annular space between the production liner 103 and the working pipe 104.
[00142] The separate production well 200 shown in Figure 2 includes a conductor casing 201, a surface casing 202 and a production casing 203, each of which can be cemented into position. In this embodiment, the production casing extends only a short distance below the lower end of the surface casing, and the remaining portion of the well below is illustrated as simply an open wellbore 206. In other embodiments, the casing of production may extend further down into the wellbore, and the open wellbore may actually include a casing or casing that may be drilled or otherwise porous to allow the passage of deposits produced within the wellbore. Internal to the production liner is a work pipe 204 that is used to release the recovered deposits to the surface, and the production pipe is surrounded near the lower end with a production seal cap 210 that provides a seal.
[00143] The recovered methane stream 251 released to the surface of the production well 200 may undergo one or more processing steps, and all or a portion of the methane stream may be directed back to the combustor system. For example, the recovered deposit stream can be processed through one or more of an expander to reduce the flow pressure, one or more separation units to separate one stream of pure methane to trade and/or separate another stream of hydrocarbon gas from any CO2 (and/or impurities - eg H2S), and another power generation turbine, all described above in relation to Figure 1. As illustrated in Figure 2, a fraction of methane flux 251 can be directed to the fuel source. This fraction can be a combination of one or more hydrocarbon gases and can include any impurities produced in the methane stream. Another fraction of the methane flow can be directed to the working fluid source. This fraction may be a separate CO2 stream and may include any impurities produced in the methane stream.
[00144] The choice of using surface combustion or downhole combustion may depend on a variety of factors, including the type of material to be recovered and the physical conditions of the formation. Typically, any system can be employed for improved recovery of any fossil fuel that is in a fluid form - for example, gaseous hydrocarbons, low viscosity oils and even high viscosity oils. For very high viscosity oils and other highly viscous hydrocarbons (eg bitumen, tar sands, and shale oil), downhole combustion systems can be advantageous due to the ability to easily provide a high combustion product. temperature which may include a significant fraction of steam, which may be beneficial in increasing the fluidity of such higher viscosity materials.
[00145] With either surface combustion or downhole combustion, a variety of combustion fuels can be used. Specifically, gaseous hydrocarbons and liquid petroleum can be used, and combustion fuel can thus be formed at least in part from the combustible material that is recovered by the methods. Combustion methods can also include solid fuels such as combustion fuel. For example, charcoal can be used, preferably in a particularized or fluidized state. In such embodiments, it may be useful for the systems of the invention to include a plurality of combustors.
[00146] For example, Figure 3 illustrates a partial view of the surface combustion modality illustrated in Figure 2 as modified to incorporate a partial oxidation combustor 600. Figure 3 illustrates a cross section of a typical geological formation consisting of (a from top to bottom) a top earth layer 2, a low porosity rock layer 3 (such as shale), and a combustible material reservoir 8. As in the previous Figures, the injection well 100 is shown penetrating the various layers of geological formation including the combustible material layer 8. Although a single injection well is shown, it is understood that a plurality of injection wells can be utilized. Furthermore, the injection well can be a pre-existing wellbore that is modified, if necessary, to facilitate the flow of CO2 or it can be a purpose-formed borehole. The illustrated injection well 100 includes a conductor casing 101, a surface casing 102, and a production casing 103, each of which can be cemented into position. Internal to the production casing is a work tubing 104 that includes a center tube 115 for injecting the stream containing CO2 into the well. In some embodiments, the working tubing may be absent, and the release of the stream containing CO2 may proceed through the center tube alone. One or more recovery wells as illustrated in Figure 1 and Figure 2 may likewise be included in the present embodiments.
[00147] As shown in Figure 3, a 1010 solid coal fuel is supplied to the partial oxidation combustor 600, which is the first combustor in the series. Although the modality is discussed in relation to coal, it is understood that any combustible material sold can be used as described. Preferably, solid fuel, such as coal, can be individualized, such as being passed through a milling apparatus. This can be done on site, or solid fuel can be supplied in a pre-tailored form. The particle size can be such as to provide an average particle size of about 10 µm to about 500 µm, about 25 µm to about 400 µm, or about 50 µm to about 200 µm. Powdered coal can be mixed with a flowable substance to provide the coal in the form of a suspension (which can be a suspension with CO2).
[00148] In addition to solid coal fuel 1010, O2 from oxygen source 20 and CO2 from working fluid source 31 can be supplied to partial oxidation combustor 600. CO2 can be optional and can be the source of the fluidizing medium. CO2 can also be used to cool the partial oxidation combustor 600. Preferably, the amount of CO2 used is sufficient to cool the temperature of the partial oxidation combustion stream exiting the partial oxidation combustor so that any ash that is present in a solid form can be safely removed. Consequently, CO2, coal, and O2 can be supplied to the partial oxidation combustor in ratios such that the coal is only partially oxidized to produce a partially oxidized combustion product stream comprising CO2 along with one or more of H2, CO, CH4 , H2S and NH3. CO2, coal and O2 also preferably can be introduced into the partial oxidation combustor 600 in necessary ratios so that the temperature of the partially oxidized combustion product stream is sufficiently low that all ash present in the stream is in the form of solid particles. which can be easily removed by one or more separators and/or filters - for example a cyclone filter. As shown in Figure 3, ash removal through filter 650 is shown. In specific embodiments, the temperature of the partially oxidized combustion stream may be less than about 1,100oC, less than about 1000oC, less than about 900oC, less than about 800oC, or less than about 700oC . In other embodiments, the temperature of the partially oxidized combustion stream can be about 300oC to about 1000oC, about 400oC to about 950oC, about 500oC to about 900oC. The filtered partially oxidized combustion stream leaving the filter 650 can be directly introduced into the perspiration cooled combustor 300. This introduction is provided along with the CO2 stream from the oxygen source 20 and the recycled CO2 working fluid from the source of working fluid 31. Combustion at this point may proceed similarly as otherwise described herein. Combustible materials in the partially oxidized combustion stream are burned in combustor 300 in the presence of O2 and CO2 to provide the combustion stream comprising CO2. This flow can be expanded through a 350 turbine to produce energy (eg through a generator). Turbine discharge flow may be passed through one or more processing components 375, and introduced into center tube 115 for injection into the wellbore. Of course, it is understood that such partial oxidation modalities may be adapted to downhole combustor modalities as otherwise described herein, particularly in relation to Figure 1.
[00149] The present invention also provides general improvements over flooding methods known in the art. Because the stream containing CO2 formed and used in the present invention is a flux of combustion product, the stream containing CO2 can also provide a significant amount of heat to the formation. The heat from combustion thus can be transferred to a portion of the formation, and such heating can function to facilitate improved recovery of deposits therein, particularly with respect to fossil fuels. If desired, the stream containing CO2 can still be supplied at temperatures sufficient to facilitate the breakdown of long-chain hydrocarbons, such as in a crude oil formation. This can be particularly useful for improving the recovery of high viscosity oils and even other highly viscous deposits.
[00150] In any of the systems and methods that may be used in accordance with the invention, the production stream removed from the production well or wells will typically comprise a mixture of materials. For example, recovered fossil fuels may include a fraction (and even high amounts in certain cases) of hydrogen sulfides, which can be removed, if desired, to provide an essentially pure fossil fuel stream. Likewise, any CO2 that passes through the formation and into the recovery stream must typically be removed to provide a sealable fossil fuel. The present invention utilizing a combustion process to supply the stream containing CO2 used for enhanced recovery can alleviate or eliminate the adverse effects of the presence of impurities in a stream of recovered fossil fuels. For example, since the combustion process can be integrated with a highly efficient and clean supercritical energy cycle using CO2 as the working fluid (as referenced above), such a cycle can effectively handle fuel streams containing a large fraction. of sulfur compounds (and other impurities). Consequently, mixtures of fossil fuels, CO2, H2S and other impurities can be used as the fuel in the combustion process, even with high content CO2, H2S and/or other impurity fractions. Therefore, by way of example, a variety of combinations of oils, light gases, CO2, sulfur compounds, and other impurities can be injected directly into the energy production cycle for use in combustion and power generation to produce additional CO2 and electricity. . Likewise, in high-pressure, high-temperature downhole combustion modalities, the input combustion fuel may be in the range of being an essentially pure hydrocarbon to being a blend of one or more hydrocarbon fuels with a variety of impurities in a variety of combinations. In other words, the combustion process according to the invention which produces CO2 for injection in the enhanced recovery techniques can proceed essentially unhindered, including in the presence of significant amounts of impurities.
[00151] The fraction of a recovery stream that is used as a combustion fuel in combustion to produce more CO2 for improved recovery (and optionally energy production) may vary depending on the nature of the formation and any materials sealables that can be extracted from the flow. For example, in improved oil recovery, the recovery stream will include crude oil and possibly water, gaseous hydrocarbons, and/or H2S. In some embodiments, it may be useful for a fraction of crude oil to be used as the combustion fuel. Typically, such use will occur after the oil recovery stream has gone through the separation steps useful to extract other components from the stream, such as natural gas and/or water.
[00152] When a recovery stream comprising crude oil also contains a sufficient fraction of gaseous hydrocarbons, specific processing steps can be applied to separate the gaseous hydrocarbons from the crude oil. The gaseous hydrocarbons (including the various impurities included therein) can then be used as the combustion fuel. In specific embodiments, gaseous hydrocarbons (which may comprise primarily methane as the hydrocarbon gas component) may include a significant content of H2S. The present invention is particularly useful in that corrosive gas can be introduced directly into the combustor without any requirement for sweetening (i.e. no significant content of H2S being removed), although sweetening is not necessarily prevented. Beneficially, combustion can be carried out using corrosive gas without actually decreasing the efficiency of the combustion cycle (the efficiency being actual energy production versus theoretical energy production based on the lowest heating value of the natural gas fuel). This is illustrated in Figure 4 where the efficiency of energy production through natural gas combustion is shown as a function of the corrosive gas content of the original crude oil recovery stream. As seen therein, the efficiency based on input (ie, the efficiency based on the total fuel input including natural gas and H2S) remains essentially constant as the H2S content increases, which indicates that the presence of H2S does not it decreases the effectiveness of the process. The use of corrosive gas, however, can be characterized as being beneficial compared to the use of pure natural gas because fuel-based efficiency (ie, efficiency based only on the potential energy production of natural gas) currently shows a slight increase as the H2S content increases. This is because the actual amount of natural gas that is flared decreases as the H2S content increases with substantially no loss in actual energy production. Combustion of H2S as a recovered natural gas stream component can thus function as a simplified means for H2S removal. For example, a natural gas stream that includes H2S can be introduced into a combustor with an oxidant and optionally CO2 (which may be at least partially present in the natural gas stream in addition to H2S). The combustion flow (where H2S is converted to SO3 by reacting with oxygen in the combustor) can be passed through a turbine for energy production (eg, through an electric generator connected to the turbine) and then through of a heat exchanger to reduce the temperature of the flow. The cooled flow (eg less than about 90oC, less than about and 50oC, less than about 30oC) may have a pressure that is greater than about 8 MPa, greater than about 12 MPa or greater than about 15 MPa. This stream can then be processed through one or more separation units, such as a condenser and an acid reactor, where sulfur originally introduced as H2S is removed as sulfuric acid in the acid reactor.
[00153] Although the recovered fossil fuel stream may contain one or more impurities (including CO2), in various embodiments, the systems and methods of the invention can be characterized as venting into the environment only one or more of the fossil fuels (which are collected for sale or direct use), electricity, and safe controlled tailings flows that are also collected and safely removed from the system. This can be achieved in light of the specific processing that can be applied to the recovered fossil fuel stream, which processing can be customized based on the current composition of the stream.
[00154] For example, a reclaimed stream may contain significantly only combustible material and CO2. As described above, such mixtures of materials can undergo a separation process to extract combustible materials that can be condensed at the given pressure or otherwise are in a liquid state under ambient conditions. Thus, a sealable product stream of liquid combustible material can be provided. The remaining stream can consist essentially of combustible material (particularly light hydrocarbons or gaseous hydrocarbons) and CO2, and this stream can be used directly as combustion fuel in the defined combustion process. In this way, the defined combustion process can have the characteristic of recovering virtually 100% of the total CO2 in its fuel feed (including any CO2 returned) - that is, with virtually zero CO2 emission to the atmosphere. Furthermore, since the recovered mixture of CO2 and gaseous hydrocarbons can be released directly to the combustion process, there is no need to separate CO2 from low molecular weight hydrocarbons, such as using absorption processes. , physical separation or hybrid solution required in the prior art.
[00155] In certain embodiments, an oil production process according to the invention may involve the production from the well of a light pressure fluid that must be reduced in pressure to separate a fraction of liquid oil and a gas stream . Such a situation is described above in relation to a downhole combustion mode, but such disclosure may likewise apply to surface combustion systems and methods.
[00156] Pressure reduction for the separation of liquid oil fractions and gaseous hydrocarbon fractions (which will typically include any fraction of CO2) can be performed in a number of stages with gas separation at each stage to minimize recompression energy of gas. Limiting the pressure in the stages also has the benefit of fractionating the gases in a more controlled aspect, thus allowing for the separation of gas for commercial dispersion. This can be particularly useful where one or more of these fractionated gases has commercial value. The gas stream that degass at a particular pressure level can be further processed for collection as opposed to being returned to the process for combustion. The waste gas stream may contain a very large fraction of CO2. Again, the invention thus can overcome limitations in the known art - that is, the requirements that recovered hydrocarbon gas streams be treated in process units, such as Ryan-Holmes and LTX, to produce pipeline grade natural gas, gas liquid propane (LPG), and a fraction of CO2 that is recycled to other recovery methods.
[00157] In improved oil recovery methods it is common for the deposit recovery stream to comprise mixtures of crude oil, gaseous hydrocarbons (eg methane) and water in a variety of proportions depending on the exact nature of the formation. In some embodiments, known techniques and processes for fractional distillation can be used to separate the recovery stream components. Desirable procedures for isolating the desired fractions can thus be identified in light of the entirety of the present disclosure in combination, as usable, with known art procedures. As an example, to process mixtures for component separation, it may be desirable for the recovery flow to be in a favorable temperature range - for example, about 10oC to about 50oC, about 15oC to about 40oC, or otherwise the ambient surface temperatures of the formation site. Other processing temperatures are not excluded and may in fact be desired in some embodiments. It is understood, however, that the following discussion regarding process pressures may vary based on the exact temperature of the recovery stream. Consequently, in some embodiments, it may be desirable for the recovery flow to be adjusted in temperature before going through any pressure limiting separation steps or during pressure limiting steps (e.g., increasing or decreasing the temperature before transition the flow from one process pressure to a different process pressure.
[00158] As an example, a recovery stream comprising an oil/gas/water mixture can be recovered at a pressure greater than about 6 Mpa (60 bar), greater than about 7.5 MPa (75 bar). ), greater than about 9 MPa (90 bar), or greater than about 10 MPa (100 bar). When the stream is processed at a temperature of about 15°C to about 40°C, the pressure of the stream can first be reduced to about 5 Mpa (50 bar). At this pressure, possible components of the mixture that can be extracted in gaseous form include CH4, C2H2, C2H4, H2, Ar, N2 and He. Substantially all of the CO2 present can likewise be extracted as a gas at this pressure. The flow pressure can then be reduced to about 0.7 Mpa (7 bar). At this pressure, possible components of the mixture that can be extracted in gaseous form include C2H6, all C3 compounds (eg C3H8) and H2S. The pressure can then be reduced to about 2 bar (0.1 MPa). At this pressure, possible components of the mixture that can be extracted in gaseous form include all C4 compounds (eg C4H10) and additional H2S. The recovery stream after this mainly consists of water, and any residual H2S (although there may be up to about 3 g/L of H2S dissolved in the water at this temperature and pressure, and the oil fraction may also include residual amounts of H2S dissolved in it. Such mixture can be reduced to ambient pressure at this point and processed through an oil/water separator. The recovered oil can be sent to tanks, a pipeline, or other storage or transfer means as desired. be reinjected in the same or a different formation, or the water can be stored or transferred to another location.
[00159] It is understood that even more and/or different pressure stages can be used to isolate specific components of a recovered flow. Furthermore, any combination of pressure limiting stages that can be envisaged in light of the present disclosure is encompassed herein. Once the chemical composition of a recovery stream is identified, the above scheme can be particularized to the specific chemical composition to break down the specific components of the recovery stream as desired.
[00160] In certain embodiments, it may be desirable to isolate a methane gas stream (or streams comprising methane and/or other gaseous hydrocarbons - include combinations of gaseous compounds that may be commercially recognized as natural gas) from a stream of recovery product. Such recovery product stream may be a crude oil stream, as discussed above, which includes a gas fraction. In these embodiments, the high pressure fraction described above can be extracted and further processed to isolate one or more desired product streams. In other embodiments, the recovery product stream may comprise primarily gaseous materials, such as in improved recovery from a natural gas formation or in improved coal bed metal production. In such embodiments, the recovery stream can comprise methane, other gaseous fuels, and/or non-combustible gases such as inert gases or Co2. In some embodiments, separation of gaseous components can be accomplished by techniques known in light of the present disclosure.
[00161] As an exemplary embodiment, a recovery product stream comprising materials such as CH4, C2H2, C2H4, H2, Ar, N2, He and CO2 can be separated into three streams. The first stream can include components such as Ar, N2, He and H2. The second stream may include predominantly CH4, and possibly small amounts of C2H2, C2H4, C2H6 and C3 hydrocarbons (which mixture can be recognized as a natural gas stream). The third stream may predominantly include C2H2 and C2H4, and may include small amounts of C2H6, and C3 hydrocarbons. The above distillation procedure can be carried out at significantly low temperatures - for example, around -150oC to less than -100oC. Under such conditions, the differential vapor pressures of the gases can be used to carry out the distillations. A variety of temperatures and pressures can be used to effect distillations that depend on the composition of the raw gas stream and the desired purities of the natural gas product stream (or other gas product stream). Such conditions can be identified in light of the present disclosure and art-recognized distillation procedures.
[00162] The incorporation of power generation components can be useful to provide electricity for grid distribution and/or indoor use. The associated energy cycle components can essentially function as scavengers to capture all polluting by-products (such as sulfur, nitrogen, ash, heavy metals, and the like) and convert them into their most benign and easily sealable or disposable forms. Sulfur can be converted to sulfuric acid; nitrogen compounds can be converted to nitric acid; metals can be converted to metal salts; ash can be converted to non-leachable ash. In various embodiments, the energy output can vary from a small percentage of the total energy of fuel material exploited to a large percentage. It can be 100% in the case of coal, where electricity is more valuable than coal unless coal must be converted to liquid fuels like gasoline, in which case, electricity production may just be enough to power the systems. process. This can be in the range of about 10% to about 50%, about 15% to about 40%, or 20% to 35% of the total energy of the exploited combustible material. In modalities where the product that is exploited is oil, the electrical generation can only be minimized to what is necessary to execute the associated systems. For example, in improved oil recovery, about 1% to 10% wax, about 1% to about 7%, or about 2% to about 5% of the total energy of the exploited oil can be converted to energy on site.
[00163] In the various forms described above, the present invention can thus provide a combustion process that produces a stream of pure CO2 at high pressure for injection into a formation to improve removal of a deposit therefrom, particularly a fossil fuel deposit . Although the combustion process may require the input of a carbonaceous material (including oil, natural gas, etc.), the CO2 stream produced may contain substantially all of the CO2 that was present in the fossil fuel feed to the combustor. Thus, the methods of the invention can be characterized as burning a fossil fuel for improved recovery of another fossil fuel. Preferably, the amount of fossil fuel recovered via the method of the invention can significantly exceed the amount of fossil fuel introduced into the combustion system so that the methods and systems are economically advantageous for improved fossil fuel recovery. Furthermore, significantly all of the CO2 produced by the combustion process is recovered as a component of the recovery stream exiting one or more production wells, becomes sequestered in the formation into which it was injected, or a combination of both. In either case, CO2 directly produced by the combustion process is contained within the method parameters in order to be sequestered, recycled into the combustion process, or otherwise captured.
[00164] By way of example, a combustion system in accordance with the present invention may comprise a combustor in fluid communication with an energy generating apparatus such as a turbine. A fuel can be burned in the combustor, and the resulting CO2-containing combustion product stream can pass to the turbine where the stream is expanded to produce energy. The stream containing expanded CO2 can then be passed through tubing or other suitable apparatus in fluid connection with the turbine to an injection well located in a formation containing fossil fuel, such tubing optionally extending a distance down into the well. injection. The stream containing injected CO2 can propagate through the formation containing fossil fuel in order to improve fossil fuel removal therefrom, such as by the various methods described herein. As the stream containing CO2 further propagates through the formation, a combination of fossil fuel and CO2 from the stream can move to a low pressure zone, such as a production well, and the CO2 stream. Combined fossil fuel can be extracted from the production well. In production, the systems of the invention may comprise piping in fluid communication with the recovery well, said piping releasing the recovered deposits to one or more components in fluid communication therewith. Such components are already described above.
[00165] As already indicated, the methods and systems of the invention can be customized to the specific requirements of the deposit to be recovered from a formation. For example, in relation to fossil fuel recovery, the reports of a system and method according to the invention can be customized by working through a decision tree that considers factors such as the following:
[00166] whether the nature of the formation and the physical parameters needed to improve recovery favors the use of surface combustion or downhole combustion;
[00167] if it is desirable for the CO2 released into the formation to be in a gaseous state or a supercritical state;
[00168] if it is desirable for the stream containing CO2 to further include steam or other material useful to further enhance fossil fuel recovery;
[00169] if it is desirable for the flux of combustion product to be used initially in an energy production method prior to injection into the formation;
[00170] if it is desirable for the flux of combustion product to be otherwise adjusted in pressure and/or adjusted in temperature for injection into the formation; and
[00171] if it is necessary to filter or otherwise separate one or more components from the combustion product stream prior to injection into the formation.
[00172] A specific advantage of the present invention arises from the ability to use all or a fraction of fossil fuel that is recovered as the fuel for the combustor. This can totally eliminate the need to release fuel from a source external to a combustor site. The type of fuel available for the combustor may vary depending on the fossil fuel(s) present in the formation and the desired recoverable product that is the main economic driver of the well or field.
[00173] For example, in an enhanced oil recovery modality, the CO2/fossil fuel stream can be processed to separate any liquid oil or other liquid hydrocarbons present. An initial decompression step can be used as described above. The total gas stream removed from the liquid separation can optionally be recompressed and then can be directly introduced to the combustion process as all or part of the required combustion fuel. If the residual hydrocarbon gas fraction exceeds combustion fuel requirements, further separation steps, as described above, may be applied to isolate one or more commercial hydrocarbon gas components.
[00174] As another example, in an improved natural gas recovery modality and/or an improved coal bed methane recovery modality, the total hydrocarbon gas production (the largest portion being methane) will preferably significantly exceed fuel requirements for the combustion process. Consequently, the CO2/methane flow can be separated into two or more fractions. A fraction (representing a portion of the total produced gas flow) can optionally be recompressed and then directly introduced into the combustion process as the combustion fuel. The remaining fraction(s) go through various separation processes as required to isolate the methane (or other gases that can be sold, such as propane or butane) to market. Preferably, substantially all of the CO2 will be broken down into the first fraction that is used as the fuel component. In such embodiments, the produced methane stream can be introduced directly into a natural gas pipeline with substantially no need for purification other than LPG recovery possible. Likewise, when the natural gas component in an enhanced oil recovery method is used as the combustion fuel, the products from the enhanced oil recovery system can be substantially oil only, (optionally) LPG and (optionally) ) electricity.
[00175] The systems and methods of the invention may be particularly advantageous for even more reasons. For example, the systems and methods of the invention can reduce operating costs and/or capital costs required to extract fossil fuels. In addition, systems and processes can create valuable by-products including, but not limited to electricity, ammonia, oil, synthesis gas, hydrogen, petroleum and petroleum products, natural gas, other fossil fuels, thermal heating, steam, and other materials that may be apparent to one skilled in the art armed with the present disclosure. Furthermore, the methods of the invention can eliminate any requirement for external natural gas, liquid fuel, or solid fuel that may be required in a combustion process. Furthermore, the methods of the invention can eliminate any requirement for the separation of CO2, sulfur, CO, petroleum gases, or other impurities.
[00176] In further embodiments, the combustion process used to produce the CO2 in accordance with the invention can burn such impurities included in the fossil fuel stream to a form that provides easily treated tailings streams. For example, all sulfur compounds can be converted to sulfuric acid which is easily reacted at minimal capital and operating costs with limestone to form sealable gypsum or can be produced as solid sulfur.
[00177] The present invention is further beneficial in that a reliable, consistent, clean source of CO2 can be provided for use as an enhanced recovery fluid. The direction of CO2 produced as a by-product of energy production for the recovery method beneficially prevents the immediate release of CO2 to the atmosphere as CO2 will certainly be sequestered in the fossil fuel reservoir after pumping down the well for recovery or will be recycled through the combustion system. The amount of CO2 sequestered in the formation may depend on oil miscibility and reservoir geology. CO2 that is not deposited in the reservoir can be recompressed and recycled for further improved fossil fuel recovery. The ratio of recycled/new CO2 for injection, and therefore the amount of CO2 stored in the reservoir, can range from 0 to about 3 depending on the parameters specified above as well as the duration of the well. In certain modalities, the average rate can be such that approximately 50% by mass of injected CO2 is recycled and therefore approximately 50% by mass of CO2 can be sequestered in the reservoir, displacing fossil fuels coming from the surface.
[00178] Many modifications and other embodiments of the invention will come to mind to one skilled in the art to which the invention belongs having the benefit of the teachings presented in the above descriptions and associated drawings. Therefore, it is to be understood that the invention is not to be limited to the specific embodiments disclosed and that modifications and other embodiments are intended to be included within the scope of the appended claims. Although specific terms are used in this document, they are used in a generic and descriptive sense and not for the purpose of limitation.

权利要求:
Claims (41)
[0001]
1. Method for recovering a deposit of combustible material from a formation, characterized in that it comprises: providing a combustion fuel (10) and an oxidant (20) to a combustor (300) positioned above ground; burning combustion fuel (10) to provide a CO2 containing stream comprising supercritical CO2; expanding the CO2 containing stream through a turbine (350) adapted for power generation to form an expanded CO2 containing stream; and injecting at least a portion of the CO2 from the expanded stream containing CO2 into the formation, including the deposit of combustible material for recovery, so that at least a portion of the combustible material in the formation and at least a portion of the flow of the CO2 stream flows from the formation and into a recovery well (200).
[0002]
2. Method according to claim 1, characterized in that it further comprises, prior to said injection step, sequentially passing the expanded stream containing CO2 through a heat exchanger (375), which cools the stream containing CO2 and through one or more separators (375), which remove one or more minor components present in the stream containing CO2.
[0003]
3. Method according to claim 2, characterized in that it further comprises, before said injection step, separating the stream containing CO2 into a stream of CO2 injection, which is injected in the formation and a stream of recycling CO2 supplied in the combustor as a working fluid.
[0004]
4. Method according to claim 3, characterized in that it further comprises one or more of compressing the recycle CO2 stream by passing the stream through a compressor (375) and heating the recycle CO2 stream passing the current through a heat exchanger (375) which cooled the expanded stream containing CO2.
[0005]
5. Method according to claim 4, characterized in that it further comprises providing the CO2 recycling stream in the combustor (300) as the working fluid.
[0006]
6. Method according to claim 5, characterized in that the CO2 recycling stream is supplied to the combustor (300) at a pressure of at least about 2 MPa.
[0007]
7. Method according to claim 5, characterized in that the combustor (300) is a perspiration cooled combustor and wherein at least a portion of the CO2 recycling stream is supplied to the perspiration cooled combustor (300) such as at least a portion of a perspiration fluid used to cool the perspiration cooled combustor (300).
[0008]
8. Method according to claim 5, characterized in that the CO2 recycling stream supplied in the combustor (300) has a purity of at least 95% molar.
[0009]
9. Method according to claim 1, characterized in that the expanded stream containing CO2 has a pressure of at least 1.5 MPa.
[0010]
10. Method according to claim 1, characterized in that the stream containing CO2 injected into the formation has a pressure of at least 7.5 MPa.
[0011]
11. Method according to claim 1, characterized in that the stream containing CO2 injected into the formation comprises supercritical CO2.
[0012]
12. Method according to claim 1, characterized in that combustion is carried out at a temperature of at least 400 °C.
[0013]
13. Method according to claim 1, characterized in that it further comprises receiving from the recovery well (200) a recovery stream comprising the combustible material and CO2.
[0014]
14. Method according to claim 13, characterized in that it further comprises separating the recovery stream into a recovered gas stream and a recovered liquid stream.
[0015]
15. Method according to claim 14, characterized in that the recovered gas stream comprises methane and CO2.
[0016]
16. Method according to claim 15, characterized in that the recovered gas stream further comprises one or more of C2 hydrocarbons, C3 hydrocarbons and C4 hydrocarbons.
[0017]
17. Method according to claim 14, characterized in that the recovered liquid stream comprises oil.
[0018]
18. Method according to claim 17, characterized in that the oil comprises crude oil.
[0019]
19. Method according to claim 14, characterized in that the recovered liquid stream comprises a fluidized solid combustible material.
[0020]
20. Method according to claim 14, characterized in that it comprises directing at least a portion of the recovered gas stream to the combustor (300) as at least a portion of the combustion fuel.
[0021]
21. Method according to claim 14, characterized in that said separation comprises directing the recovery stream through at least one pressure reduction stage at a defined pressure, whereby one or more gas fractions of material fuel are withdrawn and the remaining fraction of the recovery stream at the set pressure comprises liquid combustible material.
[0022]
22. Method according to claim 21, characterized in that one or more of the gas fractions of combustible material comprise CO2.
[0023]
23. Method according to claim 22, characterized in that it further comprises directing a gas fraction of a combustible material comprising the CO2 to the combustor (300) as at least a portion of the combustion fuel.
[0024]
24. Method according to claim 23, characterized in that it further comprises passing the combustible material gas fraction through a compressor, which increases the pressure of the combustible material gas fraction before being introduced into the combustor (300 ).
[0025]
25. Method according to claim 24, characterized in that two or more of the plurality of gas fractions of combustible material comprising CO2 are combined and directed to the combustor (300) as at least a portion of the combustion fuel.
[0026]
26. Method according to claim 25, characterized in that it further comprises passing the combustible material gas fractions through a compressor that increases the pressure of the combustible material gas fractions before being introduced into the combustor (300) .
[0027]
27. Method according to claim 25, characterized in that the compressor is a multi-stage compressor.
[0028]
28. Method according to claim 22, characterized in that the gas fractions of one or more combustible material, comprising the CO2 include at least 95% by mass of the total CO2 present in the recovery stream .
[0029]
29. Method according to claim 21, characterized in that said separation results in a plurality of gas fractions of combustible material that each comprise CO2.
[0030]
30. The method of claim 14, characterized in that it comprises separating the recovered gas stream into a recovered hydrocarbon gas stream and a recovered non-hydrocarbon gas stream.
[0031]
31. Apparatus for producing a stream containing CO2 at the bottom of the well of a well (100), characterized in that it comprises: a combustor (300); a combustion fuel supply (10) in fluid connection with the combustor (300); an oxidant supply (20) in fluid connection with the combustor (300); a chamber inside the combustor (300), the fuel being combusted at a temperature of at least about 600°C to produce the stream containing CO2; and an output on the combustor (300), which supplies the current containing CO2 from the combustor (300) and into the well (100), the output comprising a conical-shaped nozzle, which concentrates the current containing CO2 from from there.
[0032]
32. System for generating CO2 and recovering a deposit of combustible material from a formation, characterized by the fact that it comprises: a combustor (300); a combustion fuel supply (10) in fluid connection with the combustor (300); an oxidant supply (20) in fluid connection with the combustor (300); a chamber within the combustor (300) configured for receiving and combusting the combustion fuel (10) to provide a CO2 containing stream comprising supercritical CO2; an injection component that delivers the stream containing CO2 in the formation, including the combustible material deposit, so that at least a portion of the combustible material in the formation and at least a portion of the CO2 stream flows from the formation to a recovery well ( 200) as a recovery stream; and one or more processing components for processing the recovered combustible material and CO2 in the recovery stream.
[0033]
33. System according to claim 32, characterized in that the one or more processing components comprises an expander, which reduces the pressure of the recovery stream.
[0034]
34. System according to claim 33, characterized in that the expander comprises a power generation turbine.
[0035]
35. System according to claim 32, characterized in that the one or more processing components comprises one or more separation units.
[0036]
36. System according to claim 35, characterized in that the one or more separation units comprise a unit, which separates a gas stream from a liquid stream.
[0037]
37. System according to claim 32, characterized in that the injection component comprises a pipe (115), which extends to a well (100) formed in the formation.
[0038]
38. System according to claim 32, characterized in that one or more combustion fuel supplies (10) and oxidant supplies (20) comprise pipes of sufficient dimensions to deliver the respective material at the bottom of the well in a well (100) formed in the formation.
[0039]
39. System according to claim 32, characterized in that the combustor (300) is configured for use at the bottom of the well in a well (100) formed in the formation.
[0040]
40. System according to claim 32, characterized in that the system is sufficiently modular in construction, so that the system can be reconfigured between a transport state and a CO2 generation state.
[0041]
41. A method for recovering a deposit of combustible material from a formation, characterized in that it comprises: providing a combustion fuel (10) and an oxidant (20) to a combustor (300); burning combustion fuel to provide a CO2 containing stream comprising supercritical CO2; injecting at least a portion of the stream containing CO2 into the formation, including the deposit of combustible material for recovery, so that at least a portion of the combustible material in the formation and at least a portion of the CO2 stream flows from the formation to a recovery well (100); receiving from the recovery well (100) a recovery stream comprising the combustible material and CO2; and separating the recovery stream into a recovered gas stream and a recovered liquid stream.

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法律状态:
2018-12-26| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

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2019-10-01| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

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2020-10-06| B06A| Notification to applicant to reply to the report for non-patentability or inadequacy of the application [chapter 6.1 patent gazette]|

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2021-02-17| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

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2021-04-20| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 20/09/2011, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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申请号 | 申请日 | 专利标题

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US38506910P| true| 2010-09-21|2010-09-21|

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US61/385,069|2010-09-21|

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US201161506429P| true| 2011-07-11|2011-07-11|

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US61/506,429|2011-07-11|

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PCT/US2011/052307|WO2012040169A1|2010-09-21|2011-09-20|Method of using carbon dioxide in recovery of formation deposits|

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