DOWNHOLE STEAM GENERATOR AND METHOD OF USE

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the inventions relate to downhole steam generators.

2. Description of the Related Art

There are extensive viscous hydrocarbon reservoirs throughout the world. These reservoirs contain a very viscous hydrocarbon, often called “bitumen,” “tar,” “heavy oil,” or “ultra heavy oil,” (collectively referred to herein as “heavy oil”) which typically has viscosities in the range from 100 to over 1,000,000 centipoise. The high viscosity makes it difficult and expensive to recover the hydrocarbon.

Each oil reservoir is unique and responds differently to the variety of methods employed to recover the hydrocarbons therein. Generally, heating the heavy oil in situ to lower the viscosity has been employed. Normally reservoirs as viscous as these would be produced with methods such as cyclic steam stimulation (CSS), steam drive (Drive), and steam assisted gravity drainage (SAGD), where steam is injected from the surface into the reservoir to heat the oil and reduce its viscosity enough for production. However, some of these viscous hydrocarbon reservoirs are located under cold tundra or permafrost layers that may extend as deep as 1800 feet. Steam cannot be injected though these layers because the heat could potentially expand the permafrost, causing wellbore stability issues and significant environmental problems with melting permafrost.

Additionally, the current methods of producing heavy oil reservoirs face other limitations. One such problem is wellbore heat loss of the steam, as the steam travels from the surface to the reservoir. This problem is worsened as the depth of the reservoir increases. Similarly, the quality of steam available for injection into the reservoir also decreases with increasing depth, and the steam quality available downhole at the point of injection is much lower than that generated at the surface. This situation lowers the energy efficiency of the oil recovery process.

To address the shortcomings of injecting steam from the surface, the use of downhole steam generators (DHSG) has been used. DHSGs provide the ability to heat steam downhole, prior to injection into the reservoir. DHSGs, however, also present numerous challenges, including excessive temperatures, corrosion issues, and combustion instabilities. These challenges often result in material failures and thermal instabilities and inefficiencies.

Therefore, there is a continuous need for new and improved downhole steam generation systems and methods of recovering heavy oil using downhole steam generation.

SUMMARY OF THE INVENTION

Embodiments of the invention relate to downhole steam generator systems. In one embodiment, a downhole steam generator (DHSG) includes a burner head, a combustion sleeve, a vaporization sleeve, and a support/protection sleeve. The burner head may have a sudden expansion region with one or more injectors. The combustion sleeve may be a water-cooled liner having one or more water injection arrangements. The DHSG may be configured to acoustically isolate the various fluid flow streams that are directed to the DHSG. The components of the DHSG may be optimized to assist in the recovery of hydrocarbons from different types of reservoirs.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a downhole steam generator system.

FIG. 2 illustrates a cross sectional view of the downhole steam generator system.

FIG. 3 illustrates a burner head assembly of the system.

FIGS. 4, 5, and 6 illustrate cross sectional views of the burner head assembly.

FIG. 7 illustrates an igniter for use with the system.

FIG. 8 illustrates a cross sectional view of a liner assembly of the system.

FIGS. 9-13 illustrate cross sectional views of a fluid injection strut and a fluid injection system.

FIGS. 14A and 14B illustrate a fluid line assembly for use with the system.

FIGS. 15-43 illustrates chart, graphs, and/or examples of various operational characteristics of embodiments of the system and their components.

DETAILED DESCRIPTION

FIGS. 1 and 2 illustrate a downhole steam generation system 1000. Although described herein as a “steam” generation system, the system 1000 may be used to generate any type heated liquid, gas, or liquid-gas mixture. The system 1000 includes a burner head assembly 100, a liner assembly 200, a vaporization sleeve 300, and a support sleeve 400. Burner head assembly 100 is coupled to the upper end of liner assembly 200, and the vaporization sleeve 300 is coupled to the lower end of liner assembly 200. The support sleeve 400 is coupled to the vaporization sleeve 300 and may be operable to support and lower the system 1000 into a wellbore on a work string. The components may be coupled together by a bolt and flange connection, a threaded connection, a welded connection, or other connection mechanisms known in the art. One or more fuels, oxidants, coolants, diluents, solvents, and combinations thereof may be supplied to the system 1000 to generate a fluid mixture for injection into one or more hydrocarbon-bearing reservoirs. The system 1000 may be used to recover hydrocarbons from light oil, heavy oil, partially depleted, fully depleted, virgin, and tar-sand type reservoirs.

FIGS. 3 and 4 illustrate the burner head assembly (combustor) 100. The burner head assembly 100 may be operable with an “attached flame” configuration, a “lifted flame” configuration, or some combination of the two configurations. An attached flame configuration generally results in hardware heating from convection and radiation, typically includes axisymmetric sudden expansion, v-gutters, trapped vortex cavities, and other geometrical arrangements, and is resistant to blow-off caused by high fluid velocities. An attached flame configuration may be preferable for use when a large range of operating parameters is required for the system 1000, when thermal losses from hot gas to the hardware are negligible or desired, and when cooling fluid is available. A lifted flame configuration generally results in hardware heating by radiation, and typically includes swirlers, cups, doublets/triplets, and other geometrical arrangements. A lifted flame configuration may be preferable for use when discrete design points across an operating envelope are required, where fuel injection velocity can be controlled by multiple manifolds or a variable geometry, where high temperature gas is a primary objective, and/or where cooling fluid is unavailable or limited.

The burner head assembly 100 includes a cylindrical body having a lower portion 101 and an upper portion 102. The lower portion 101 may be in the form of a flange for connection with the liner assembly 200. The upper portion 102 includes a central bore 104 for supplying fluid, such as an oxidant, to the system 1000. A damping plate 105, comprising a cylindrical body having one or more flow paths formed through the body, may be disposed in the central bore 104 to acoustically isolate fluid flow to the system 1000. One or more fluid lines 111-116 may be coupled to the burner head assembly 100 for supplying various fluids to the system 1000. A support ring 103 is coupled to both the upper portion 102 and the fluid lines 111-116 to structurally support the fluid lines during operation. An igniter 150 is coupled to the lower portion 101 to ignite the fluid mixtures supplied to the burner head assembly 100. One or more recesses or cutaways 117 may be provided in the support ring 103 and the lower portion 101 to support a fluid line that couples to the liner assembly 200 as further described below.

The central bore 104 intersects a sudden expansion region 106, which is formed along the inner surface of the lower portion 101. The sudden expansion region 106 may include one or more increases in the inner diameter of the lower portion 101 relative to the inner diameter of the central bore 104. Each increase in the inner diameter of the lower portion 101 is defined as an “injection step”. As illustrated in FIG. 4, the burner head assembly 100 includes a first (inner) injection step 107 and a second (outer) injection step 108. The diameter of the first injection step 107 is greater than the diameter of the central bore 104, while the diameter of the second injection step 108 is greater than the first injection step 107. The sudden change in diameters at the exit of the central bore 104 creates a turbulent flow or trapped vortex, flame-holding region which enhances mixing of fluids in the sudden expansion region 106, which may provide a more complete combustion of the fluids. The sudden expansion region 106 may thus increase flame stability, control flame shape, increase combustion efficiency, and support emission control.

The first and second injection steps 107, 108 may each have one or more injectors (nozzles) 118, 119, respectively, that include fluid paths or channels formed through the lower portion 101 of the body of the burner head assembly 100. The injectors 118, 119 are configured to inject fluid, such as a fuel, into the burner head assembly 100 in a direction normal (and/or at an angle) to fluid flow through the central bore 104. The injection of fluid normal to the fluid flow through the central bore may also help produce a stable flame in the system 1000. Fluid from the injectors 118, 119 may be injected into the fluid flow through the central bore 104 at any other angle or combination of angles configured to enhance flame stability. The first injection step 107 may include eight injectors 118, and the second injection step 108 may include sixteen injectors 119. The number, size, shape, and injection angle of the injectors 118, 119 may vary depending on the operational requirements of the system 1000.

As illustrated in FIGS. 5 and 6, each injection step may also include a first injection manifold 121 and a second injection manifold 123. The first and second injection manifolds 121, 123 are in fluid communication with the injectors 118, 119, respectively. Each of the first and second injection manifolds 121, 123 may be in the form of a bore concentrically disposed through the body of the lower portion 101, between the inner diameter and the outer diameter of the lower portion 101. The first and second injection manifolds 121, 123 may direct fluid received from one or more of the fluid lines 111-116 (illustrated in FIG. 3) to each of the injectors 118, 119 by channels 122, 124 for injection into the sudden expansion region 106. A plurality of first and second injection manifolds 121, 123 may be provided to supply fluid to the injectors 118, 119. One or more additional injection manifolds may be provided to acoustically isolate fluid flow to the first and second injection manifolds 121, 123. All or portions of the burner head assembly 100 may be formed from or coated with a high temperature resistant or dispersion strengthened material, such as beryllium copper, monel, copper alloys, ceramics, etc.

The system 1000 may be configured so that the burner head assembly 100 can operate with fluid flow through the first injection step 107 only, the second injection step 108 only, or both the first and second injection steps 107, 108 simultaneously. During operation, flow through the first and/or second injection steps 107, 108 may be selectively adjusted in response to pressure, temperature, and/or flow rate changes of the system 1000 or based on the hydrocarbon-bearing reservoir characteristics, and/or to optimize flame shape, heat transfer, and combustion efficiency. The composition of fluids flowing through the first and second injection steps 107, 108 may also be selectively adjusted for the same reasons. A fluid (such as nitrogen or “reject” nitrogen provided from a pressure swing adsorption system) may be mixed with a fuel in various compositions and supplied through the burner head assembly 100 to control the operating parameters of the system 1000. Nitrogen, carbon dioxide, or other inert gases or diluents may be mixed with a fuel and supplied through the first and/or second injection steps 107, 108 to control pressure drop, flame temperature, flame stability, fluid flow rate, and/or acoustic noise developed within the system 1000, such as within the burner head assembly 100 and/or the liner assembly 200.

The system 1000 may have multiple injectors, such as injectors 118, 119 for injecting a fuel. The injectors may be selectively controlled for various operation sequences. The system 1000 may also have multiple injection steps, such as first and second injection steps 107, 108, that are operable alone or in combination with one or more of the other injection steps. Fluid flow through the injectors of each injection step may be adjusted, stopped, and/or started during operation of the system 1000. The injectors may provide a continuous operation over a range of fluid (fuel) flow rates. Discrete (steam) injection flow rates may be time-averaged to cover entire ranges of fluid flow rates.

An oxidant (oxidizer) may be supplied through the central bore 104 of the burner head assembly 100, and a fuel may be supplied through at least one of the first and second injection steps 107, 108 normal to the flow of the oxidant. The fuel and oxidant mixture may be ignited by the igniter 150 to generate a combustion flame and combustion products that are directed to the liner assembly 200. The combustion flame shape generated within the burner head assembly 100 and the liner assembly 200 may be tailored to control heat transfer to the walls of the burner head assembly 100 and the liner assembly 200 to avoid boiling of fluid and an entrained air release of bubbles.

As further illustrated in FIGS. 5 and 6, the burner head assembly 100 may include a cooling system 130 having an inlet 131 (illustrated in FIG. 5), an outlet 136 (illustrated in FIG. 6), and one or more fluid paths (passages) 132, 133, 134 in fluid communication with the inlet 131 and outlet 136. The cooling system 130 is configured to direct fluid, such as water, through the system 1000 to cool or control the temperature of burner head assembly 100 and in particular the first and second injection steps 107, 108. The fluid paths 132, 133, 134 may be concentrically formed through the body of the lower portion 101 and located next to the first and second injection steps 107, 108. Fluid may be supplied to the inlet 131 of the cooling system 130 by one of the fluid lines 111-116 (illustrated in FIG. 3), and directed to at least one of the fluid paths 132, 133, 134 via a channel 137 for example. The fluid may be circulated through the fluid paths 132, 133, 134 and directed to the outlet 136 via a channel 135 for example. The fluid may then be removed from the cooling system 130 by one of the fluid lines 111-116 that are in fluid communication with the outlet 136.

Fluid path 132 may be in direct fluid communication with fluid path 133 via a channel (similar to channel 137 for example), and fluid path 133 may be in direct fluid communication with fluid path 134 via a channel (also similar to channel 137 for example). Fluid may circulate through fluid path 132, then through fluid path 133, and finally through fluid path 134. Fluid may flow through fluid path 132 in a first direction, about at least one of the first and second injection steps 107, 108. Fluid may flow through fluid path 133 in a second direction (opposite the first direction), about at least one of the first and second injection steps 107, 108. Fluid may flow through fluid path 134 in the first direction, about at least one of the first and second injection steps 107, 108. In this manner, the fluid paths 132, 133, 134 may be arranged to alternately direct fluid flow through the burner head assembly 100 in a first direction about the first and second injection steps 107, 108, then in a second, opposite direction, and finally in a third direction similar to the first direction. Fluid supplied through the cooling system 130 may then be returned to the surface or may be directed to cool the liner assembly 200 as further described below. One or more of the fluid lines 111-116 (illustrated in FIG. 3) may be connected to the burner head assembly 100 to supply fluid to the cooling system 130. A portion of fluid flowing through the cooling system 130 may be injected from at least one of the fluid paths 132, 133, 134 into the sudden expansion region 106 and/or the liner assembly 200 to control flame temperature and/or enhance surface cooling of the burner head assembly 100 and/or the liner assembly 200.

FIG. 7 illustrates the igniter 150. The igniter 150 is positioned next to the sudden expansion region 106 and configured to ignite the mixture of fluids supplied through the central bore 104 and the first and second injection steps 107, 108. An igniter port 151 may be disposed through the lower portion 101 of the burner head assembly 100 to support the igniter 150. The igniter 150 may include a glow plug through which a fuel 127 and an oxidizer 128 are directed (by fluid lines for example) and a power source 126 (such as an electrical line) is connected to initiate combustion within the system 1000. After ignition of the fluid mixture in the system 1000, the igniter 150 may be configured to permit continuous flow of the oxidizer 128 into the burner head assembly 100 to prevent back flow of hot combustion products or gases. The igniter 150 may be operated multiple times for multiple start-up and shut-down operations of the system 1000. Alternatively, the igniter 150 may include an igniter torch (methane/air/hot wire), a hydrogen/air torch, a hot wire, a glow plug, a spark plug, a methane/enriched air torch, and/or other similar ignition devices.

The system 1000 may be configured with one or more types of ignition arrangements. The system 1000 may include pyrophoric and detonation wave ignition methods. The system 1000 may include multiple igniters and ignition configurations. Gas flow may also be provided through one or more igniters, such as igniter 150, for cooling purposes. The burner head assembly 100 may have an integrated igniter, such as igniter 150, which is operable with the same oxidizer and fuel used for combustion in the system 1000.

FIG. 8 illustrates the liner assembly 200 connected to the burner head assembly 100. The liner assembly 200 may comprise a tubular body having an upper portion 201, a middle portion 202, and a lower portion 203. The inner surface of the liner assembly 200 defines a combustion chamber 210. The upper and lower portions 201, 203 may be in the form of a flange for connection to the burner head assembly 100 and the vaporization sleeve 300, respectively. The upper and lower portions 201, 203 may include first (inlet) and second (outlet) manifolds 204, 205, respectively, that are in the form of a bore concentrically disposed through the body of the upper and lower portions 201, 203 between the inner diameter and the outer diameter of the upper and lower portions 101, 203. The first and second manifolds 204, 205 are in fluid communication with each other by one or more fluid paths 206 disposed through the body of the middle portion 202. Fluid, such as water, may be supplied to the first manifold 204 by one or more fluid lines (such as fluid lines 111-116 described above), and then directed through the fluid paths 206 to the second manifold 205. The fluid flow through the fluid paths 206 surrounding the combustion chamber 210 may be arranged to cool and maintain the combustion chamber 210 wall temperatures within an acceptable operating range. The first manifold 204 may be in fluid communication with and adapted to receive fluid from at least one of the fluid paths 132, 133, 134, the inlet 131 (illustrated in FIG. 5), and the outlet 136 (illustrated in FIG. 6) of the cooling system 130 of the burner head assembly 100 described above.

As illustrated in FIGS. 8 and 9, the liner assembly 200 may further include a fluid injection strut 207 or other structural member coupled to the body of the liner assembly 200 and having a plurality of injectors (nozzles) 208 that are in fluid communication with the second manifold 205 for injection of fluid in a direction upstream into the combustion chamber 210, downstream out of the combustion chamber 210, and/or normal to the combustion chamber 210 flow. The fluid may comprise water and/or other similar cooling fluids. The fluid injection strut 207 may be configured to inject atomized droplets of the fluid into heated combustion products generated in the combustion chamber 210 (by the burner head assembly 100) to evaporate the fluid droplets and thereby form a heated vapor, such as steam for example. The liner assembly 200 may be configured for direct injection of fluid, including atomized fluid droplets, into the combustion chamber 210 from at least one of the first and second manifolds 204, 205, the fluid paths 206, and the body or wall of the upper, lower, and/or middle portions. The direct injection of fluid may occur at one or more locations along the length of the liner assembly 200. The liner assembly 200 may be configured for direct injection of fluid from at least one of the first and second manifolds 204, 205, the fluid paths 206, and the body or wall of the upper, lower, and/or middle portions, in combination with the fluid injection strut 207. The liner assembly 200 may also include a fluid injection step 209 having a plurality of nozzles 211 to cool the initial portion of the vaporization sleeve 300 below the combustion chamber 210 by injecting a thin layer of fluid or a film of fluid across the inner surfaces of the vaporization sleeve 300.

The injection strut 207 may be located at various positions within the liner assembly 200 and may be shaped in various forms for fluid injection. The injection strut 207 may also be fashioned as an acoustic damper and configured to acoustically isolate fluid flow to the combustion chamber 210 (similar to the damping plate 105 in the burner head assembly 100). The body of the liner assembly 100 and/or the injection strut 207 may be in fluid communication with a source of pressurized gas, such as air supplied to the system 1000, to assist fluid flow through the liner assembly 200 and fluid injection through the injection strut 207. The system 1000 may be provided with additional cooling mechanisms to control the combustion chamber 210 temperature or flame temperature, such as direct coolant injection through the upper portion 201 of the liner assembly 200, transpiration or film cooling of the liner assembly 200 along its length, and/or ceramic coatings may be applied to reduce metal temperatures.

FIGS. 10-13 illustrate a fluid injection system 220 (such as a gas-assisted water injection system) of the liner assembly 200. The fluid injection system 200 may be used independent of or in combination with the fluid injection strut 207 described above. A fluid (feed) line 230 (such as fluid lines 111-116 illustrated in FIG. 3) may be coupled to the liner assembly 200 for supplying a fluid, such as a gas, to a gas manifold 231 disposed in the lower portion 203 of the body to assist in the injection of atomized fluid, such as water, into the combustion chamber 210. The fluid line 230 may extend directly from the surface or may be in fluid communication with one or more of the fluid lines 111-116 that supply an oxidant to the system 1000, so that the gas comprises a portion of the oxidant supplied to the system 1000. The gas manifold 231 may have an upper plenum 221 in communication with a lower plenum 222 by a fluid path 223. The upper plenum 221 may direct the gas into the combustion chamber 210 through nozzles 224, which forms an eductor pump to assist in atomization of the water. Water from the fluid paths 206 may flow into a water manifold 227 (such as second manifold 205 described above) and through a fluid path 226 into the gas stream formed by the nozzles 224. The water may then be injected into the combustion chamber 210 as atomized droplets in a direction normal to the flow of combustion products in the combustion chamber 210. The lower plenum 222 may direct the gas into the vaporization sleeve 300 via a fluid path 229 that communicates the gas to nozzles 211, which also forms an eductor pump to assist in atomization of the water. Water may flow from the water manifold 227 through a fluid path 228 into the gas stream formed by the nozzles 211 and be injected into the vaporization sleeve 300 in a direction parallel to the flow of the combustion products exiting the combustion chamber 210. The water droplets may be injected along the longitudinal length of the vaporization sleeve 300 inner wall to film cool the inner wall and to help control the temperature of the combustion products. The fluid injection system 220 thus forms a two-stage water injection arrangement that may be located within and/or relative to the body of the liner assembly 200 and the vaporization sleeve 300 in a number of ways to optimize fluid (water) injection into the system 1000.

The system 1000 may include a twin fluid atomizing nozzle arrangement that is configured to mix or combine a gas stream and a water stream in various ways to form an atomized droplet spray that is injected into the combustion chamber 210 and/or the vaporization sleeve 300. A fluid such as water may be supplied through the fluid (feed) line 230, alone or in combination with a gas, at a high pressure to the point that the water is vaporized upon injection into the combustion chamber 210. The high pressure water may be cavitated through an orifice as it is injected into the combustion chamber 210.

The system 1000 may be configured with one or more water injection arrangements, such as the injection strut 207 and/or the injection system 220, to inject water into the burner head assembly 100, the combustion chamber 210, and/or the vaporization sleeve 300. The system 1000 may include a water injection strut connected to the body of the liner assembly 200. Water injection into the combustion chamber 210 may be provided directly from the combustion chamber wall. Injection of the water may occur at one or more locations, such as the tail end and/or the head end of the combustion chamber 210. The system 1000 may include a gas-assisted water injection arrangement. The water injection arrangements may be tailored to provide surface/wall protection and to control evaporation length. Optimization of the water injection arrangements may provide wetting of the inner surfaces/walls, achieve vaporization to a design point in a limited length, and avoid quenching of combustion flame. Fluid droplets may be injected into the combustion chamber 210 (using the fluid injection strut 207 and/or the fluid injection system 220 for example) such that the fluid droplet sizes are within a range of about 20 microns to about 100 microns, about 100 microns to about 200-300 microns, about 200-300 microns to about 500-600 microns, and about 500-600 microns to about 800 microns or greater. About 30% of the fluid droplets may have a size of about 20 microns, about 45% of the fluid droplets may have a size of about 200 microns, and about 25% of the fluid droplets may have a size of about 800 microns.

The vaporization sleeve 300 comprises a cylindrical body having an upper portion 301 in the form of a flange for connection to the liner assembly 200, and a middle or lower portion 301 that defines a vaporization chamber 310. The fluids and combustion products from the liner assembly 200 may be directed into the upper end and out of the lower end of the vaporization chamber 310 for injection into a reservoir. The vaporization chamber 310 may be of sufficient length to allow for complete combustion and/or vaporization of the fuel, oxidant, water, steam, and/or other fluids injected into the combustion chamber 210 and/or the vaporization sleeve 300 prior to injection into a reservoir.

The support sleeve 400 comprises a cylindrical body that surrounds or houses the burner head assembly 100, the liner assembly 200, and the vaporization sleeve 300 for protection from the surrounding downhole environment. The support sleeve 400 may be configured to protect the components of the system 1000 from any loads generated by its connection to other downhole devices, such as packers or umbilical connections, etc. The support sleeve 400 may protect the system 1000 components from structural damage that may be caused by thermal expansion of the system 1000 itself or the other downhole devices. The support sleeve 400 (or exoskeleton) may be configured to transmit umbilical loads around the system 1000 to a packer or other sealing/anchoring element connected to the system 1000. The system 1000 may be configured to accommodate for thermal expansion of components that are part of, connected to, or located next to the system 1000. Finally, a variety of alternative fuel, oxidant, diluent, water, and/or gas injection methods may be employed with the system 1000.

FIG. 14A illustrates a fluid line assembly 1400A for supplying a fluid, such as water to the system 1000. The fluid line assembly 1400A includes a first fluid line 1405 and a second fluid line 1420 for directing a portion of the fluid in the fluid line 1405 to the cooling system 130 of the burner head assembly 100. The second fluid line 1420 is in communication with the inlet 131 of the cooling system 130. Downstream of the second fluid line 1420 is a pressure control device 1410, such as a fixed orifice, to balance the pressure drop in the first fluid line 1405. A third fluid line 1425 is in communication with the outlet 136 of the cooling system 130 and arranged to direct fluid back into the first fluid line 1405. The first fluid line 1405 may also supply fluid to the liner assembly 200, and in particular to the first manifold 204, the second manifold 205, the fluid injection strut 207, the fluid injection system 220, and/or directly into the combustion chamber 210 through a wall of the liner assembly 200. Multiple fluid lines can be used to provide fluid from the surface to the system 1000.

FIG. 14B illustrates a fluid line assembly 1400B for supplying a fluid, such as an oxidant (e.g. air or enriched air) to the system 1000. The fluid line assembly 1400B includes a first fluid line 1430 for supplying fluid to the central bore 104 of the burner head assembly 100. A second fluid line 1455 (such as fluid line 230 illustrated in FIG. 10) may direct a portion of the fluid in the fluid line 1430 to the fluid injection strut 207 and/or the fluid injection system 220 of the liner assembly 200. A third fluid line 1445 may also direct a portion of the fluid in the fluid line 1430 to the igniter 150 of the burner head assembly 100. One or more pressure control devices 1435, 1445, 1455, such as a fixed orifice, are coupled to the fluid lines to balance the pressure drop in the fluid lines to the system 1000. Multiple fluid lines can be used to provide fluid from the surface to the system 1000.

The system 1000 may be operated in a “flushing mode” to clean and prevent chemical, magnesium or calcium plugging of the various fluid (flow) paths in the system 1000 and/or the wellbore below the system 1000. One or more fluids may be supplied through the system 1000 to flush out or purge any material build up, such as coking, formed in the fluid lines, conduits, burner head assembly 100, liner assembly 200, vaporization sleeve 300, wellbore lining, and/or liner perforations.

The system 1000 may include one or more acoustic dampening features. The damping plate 105 may be located in the central bore 104 above or within the burner head assembly 100. A fluid (water) injection arrangement, such as the fluid (water) injection strut 207, may be used to acoustically isolate the combustion chamber 210 and the inner region of the vaporization sleeve 300. Nitrogen addition to the fuel may help maintain adequate pressure drop across the injectors 118, 119.

The fuel supplied to the system 1000 may be combined with one or more of the following gases: nitrogen, carbon dioxide, and gases that are non-reactive. The gas may be an inert gas. The addition of a non-reactive gas and/or inert gas with the fuel may increase flame stability when using either a “lifted flame” or “attached flame” design. The gas addition may also help maintain adequate pressure drops across the injectors 118, 119 and help maintain (fuel) injection velocity. As stated above, the gas addition may also mitigate the impact of combustion acoustics on the first and second (fuel) injection steps 107, 108 of the system 1000.

The oxidant supplied to the system 1000 may include one or more of the following gases: air, oxygen-enriched air, and oxygen mixed with an inert gas such as carbon dioxide. The system 1000 may be operable with a stoichiometric composition of oxygen or with a surplus of oxygen. The flame temperature of the system 1000 may be controlled via diluent injection. One or more diluents may be used to control flame temperature. The diluents may include water, excess oxygen, and inert gases including nitrogen, carbon dioxide, etc.

The burner head assembly 100 may be operable within an operating pressure range of about 300 psi to about 1500 psi, about 1800 psi, about 3000 psi, or greater. Water may be supplied to the system 1000 at a flow rate within a range of about 375 bpd (barrels per day) to about 1500 bpd or greater. The system 1000 may be operable to generate steam having a steam quality of about 0 percent to about 80 percent or up to 100 percent. The fuel supplied to the system 1000 may include natural gas, syngas, hydrogen, gasoline, diesel, kerosene, or other similar fuels. The oxidant supplied to the system 1000 may include air, enriched air (having about 35% oxygen), 95 percent pure oxygen, oxygen plus carbon dioxide, and/or oxygen plus other inert diluents. The exhaust gases injected into the reservoir using the system 1000 may include about 0.5 percent to about 5 percent excess oxygen. The system 1000 may be compatible with one or more packer devices of about 7 inch to about 7⅝ inch, to about 9⅝ inch sizes. The system 1000 may be dimensioned to fit within casing diameters of about 5½ inch, about 7 inch, about 7⅝ inch, and about 9⅝ inch sizes. The system 1000 may be about 8 feet in overall length. The system 1000 may be operable to generate about 1000 bpd, about 1500 bpd, and/or about 3000 bpd or greater of steam downhole. The system 1000 may be operable with a pressure turndown ratio of about 4:1, e.g. about 300 psi to about 1200 psi for example. The system 1000 may be operable with a flow rate turndown ratio of about 2:1, e.g. about 750 bpd to about 1500 bpd of steam for example. The system 1000 may include an operating life or maintenance period requirement of about 3 years or greater.

According to one method of operation, the system 1000 may be lowered into a first wellbore, such as an injection wellbore. The system 1000 may be secured in the wellbore by a securing device, such as a packer device. A fuel, an oxidant, and a fluid may be supplied to the system 1000 via one or more fluid lines and may be mixed within the burner head assembly 100. The oxidant is supplied through the central bore 104 into the sudden expansion region 106, and the fuel is injected into the sudden expansion region 106 via the injectors 118, 119 for mixture with the oxidant. The fuel and oxidant mixture may be ignited and combusted within the combustion chamber to generate one or more heated combustion products. Upon entering the sudden expansion region 106, the oxidant and/or fuel flow may form a vortex or turbulent flow that will enhance the mixing of the oxidant and fuel for a more complete combustion. The vortex or turbulent flow may also at least partially surround or enclose the combustion flame, which can assist in controlling or maintaining flame stability and size. The pressure, flow rate, and/or composition of the fuel and/or oxidant flow can be adjusted to control combustion. The fluid may be injected (in the form of atomized droplets for example) into the heated combustion products to form an exhaust gas. The fluid may include water, and the water may be vaporized by the heated combustion products to form steam in the exhaust gas. The fluid may include a gas, and the gas may be mixed and/or reacted with the heated combustion products to form the exhaust gas. The exhaust gas may be injected into a reservoir via the vaporization sleeve to heat, combust, upgrade, and/or reduce the viscosity of hydrocarbons within the reservoir. The hydrocarbons may then be recovered from a second wellbore, such as a production wellbore. The temperature and/or pressure within the reservoir may be controlled by controlling the injection of fluid and/or the production of fluid from the injection and/or production wellbores. For example, the injection rate of fluid into the reservoir may be greater than the production rate of fluid from the production wellbore. The system 1000 may be operable within any type of wellbore arrangements including one or more horizontal wells, multilateral wells, vertical wells, and/or inclined wells. The exhaust gas may comprise excess oxygen for in-situ combustion (oxidation) with the heated hydrocarbons in the reservoir. The combustion of the excess oxygen and the hydrocarbons may generate more heat within the reservoir to further heat the exhaust gas and the hydrocarbons in the reservoir, and/or to generate additional heated gas mixtures, such as with steam, within the reservoir.

FIG. 15 shows a graph that illustrates adiabatic flame temperature (degrees Fahrenheit) versus excess oxygen (percent mole fraction in flame) during operation of the system 1000 using regular air and enriched air (having about 35 percent oxygen). As illustrated, the flame temperature decreases as the percentage of excess oxygen in the flame increases. As further illustrated, enriched air may be used to generate higher flame temperatures than regular air.

FIG. 16 shows a graph that illustrates adiabatic flame temperature (degrees Fahrenheit) versus pressure (psi) during operation of the system 1000 using enriched air (having about 35 percent oxygen) and a resultant flame content having about 0.5 percent excess oxygen and about 5.0 percent excess oxygen. As illustrated, the flame temperature increases as the pressure increases, and lesser amounts of excess oxygen in the combustion products increases flame temperatures.

FIGS. 17-20 illustrate examples of the operating characteristics of the system 1000 within various operational parameters, including the use of enriched air. FIGS. 17 and 19 illustrate examples of the system 1000 having a combustion chamber 210 (see FIG. 8) diameter of about 3.5 inches, and a 7 or 8⅝ inch thermal packer device having a packer inner diameter of about 3.068 inches. FIGS. 18 and 20 illustrate examples of the system 1000 having a combustion chamber 210 (see FIG. 8) diameter of about 3.5 inches, and a thermal packer device having a packer inner diameter of about 2.441 inches. The examples illustrate the system 1000, and in particular the burner head assembly 100 and/or combustion chamber 210, operating with a pressure at about 2000 psi, 1500 psi, 750 psi, and 300 psi. The examples further illustrate the system 1000 operating with a water flow rate of 1500 bpd and 375 bpd.

FIG. 21 shows a graph that illustrates fuel injection velocity (feet per second) versus pressure (psi) in the burner head assembly 100 and/or combustion chamber 210 during operation of the system 1000 at a maximum fuel injection flow rate (e.g. 1500 bpd) and ¼ of the maximum fuel injection flow rate (e.g. 375 bpd). In addition, at about 800 psi and below, 24 injectors (such as injectors 118, 119) were used to inject fuel into the system 1000, and above 800 psi, only 8 injectors (such as injectors 118) were used to inject fuel into the system 1000. As illustrated, the fuel injection velocity generally decreases as the pressure increases, and higher fuel injection velocities can be achieved at higher pressure with the use of only 8 injectors as compared to the use of 24 injectors.

FIGS. 22A and 22B show graphs illustrating jet penetration in cross flow and from about a 0.06 inch injector (such as injectors 118, 119). Generally, jet penetration increases as the jet to free-stream momentum ratio increases.

FIG. 23 shows a graph that illustrates percentage of pressure drop across the injections (such as injectors 118, 119) versus pressure (psi) in the burner head assembly 100 and/or combustion chamber 210 during operation of the system 1000 at a maximum fuel injection flow rate (e.g. 1500 bpd) and ¼ of the maximum fuel injection flow rate (e.g. 375 bpd). In addition, at about 800 psi and below, 24 injectors (such as injectors 118, 119) were used to inject fuel into the system 1000, and above 800 psi, only 8 injectors (such as injectors 118) were used to inject fuel into the system 1000. As illustrated, the percentage of pressure drop generally decreases as the pressure increases, and higher percentages of pressure drop occur with the use of only 8 injectors as compared to the use of 24 injectors.

FIGS. 24-29 show graphs illustrating the effect of a diluent, specifically nitrogen, mixed with a fuel supplied to the system 1000 to control the fuel injection pressure drop. FIGS. 24 and 25 shows graphs that illustrate a percentage of pressure drop across the injections (such as injectors 118, 119) versus pressure (psi) in the burner head assembly 100 and/or combustion chamber 210 during operation of the system 1000 at a maximum fuel injection flow rate (e.g. 1500 bpd) and using two injection manifolds (e.g. first and second injection steps 107, 108). As illustrated, the injector pressure drop is maintained above about 10 percent as the pressure increases from about 300 psi to above about 2000 psi. Also illustrated is that the percentage of the available nitrogen used, as well as the mass flow of nitrogen relative to the mass flow of the fuel, increase as the pressure increases.

FIGS. 26 and 27 shows graphs that illustrate a percentage of pressure drop across the injections (such as injectors 118, 119) versus pressure (psi) in the burner head assembly 100 and/or combustion chamber 210 during operation of the system 1000 at a maximum fuel injection flow rate (e.g. 1500 bpd) and using one injection manifold (e.g. first and/or second injection step 107, 108). As illustrated, the injector pressure drop is maintained above about 10 percent as the pressure increases from about 300 psi to above about 2000 psi. Also illustrated is that the percentage of the available nitrogen used, as well as the mass flow of nitrogen relative to the mass flow of the fuel, increase as the pressure increases. As noted in the graph, an additional source of diluent may be needed when the percentage of the available nitrogen used is at 100 percent.

FIGS. 28 and 29 shows graphs that illustrate a percentage of pressure drop across the injections (such as injectors 118, 119) versus pressure (psi) in the burner head assembly 100 and/or combustion chamber 210 during operation of the system 1000 at a minimum fuel injection flow rate (e.g. 375 bpd) and using one injection manifold (e.g. first and/or second injection step 107, 108). As illustrated, the injector pressure drop is maintained at or above about 10 percent as the pressure increases from about 300 psi to above about 2000 psi. Also illustrated is that the percentage of the available nitrogen used, as well as the mass flow of nitrogen relative to the mass flow of the fuel, increase as the pressure increases. As noted in the graph, an additional source of diluent may be needed when the percentage of the available nitrogen used is at 100 percent.

FIG. 30 shows a graph that illustrates an operating range of heat flux (q) versus adiabatic flame temperature (degrees Fahrenheit) at the face of the injector steps (e.g. first and/or second injection step 107, 108) during operation of the burner head assembly 100. As illustrated, as the flame temperature increases from about 3000 degrees Fahrenheit to about 5000 degrees Fahrenheit, the heat flux increases from about 400,000 BTU/ft²per hour to about 1,100,000 BTU/ft²per hour.

FIGS. 31-33 show graphs that illustrates the gas side and the water side temperatures (degrees Fahrenheit) of the burner head assembly 100 material (including beryllium copper) and the liner assembly 200 material versus adiabatic flame temperature (degrees Fahrenheit) during operation of the system 1000. As illustrated, the temperatures of the materials on the gas side are higher as compared to the water side, and generally increase in temperature as the flame temperature increases. Also illustrated is the temperature of the material on the water side generally remains the same or increases as the adiabatic flame temperature increases based on the material used.

FIG. 34 illustrates a graph comparing the gas (hot) side and water (cold) side wall temperatures of a beryllium copper formed burner head assembly 100 and/or liner assembly 200 under a 375 bpd water flow rate (550 psi initial water pressure) and a 1500 bpd water flow rate (2200 psi initial water pressure). As illustrated, the gas side wall temperature is greater under the 375 bpd water flow rate operating parameter than when operating under the 1500 bpd water flow rate due to the reduced water cooling velocity. Also illustrated is that a high degree of wall sub-cooling is maintained to prevent the possibility of boiling in the fluid paths. The burner head assembly 100 may be formed from a monel 400 based material, may include about a 1/16 inch wall thickness between the gas side and the water side, and may be configured to maintain a gas side wall temperature of about 555 degrees Fahrenheit, a water side wall temperature of about 175 degrees Fahrenheit, a water saturation temperature of about 649 degrees Fahrenheit, and a wall sub-cooling temperature of about 475 degrees Fahrenheit.

FIG. 35 shows a graph that illustrates the ideal 100 percent vaporization distance (feet) of a fluid droplet versus the fluid droplet size (mean diameter in microns) (degrees Fahrenheit) during operation of the system 1000. As illustrated, as the fluid droplet size increases from about 0.0 microns to about 700 microns, the distance to achieve 100 percent vaporization increases from about 0.0 feet to about 4 feet.

FIG. 36 illustrates an example of the operating characteristics of the system 1000 during start up, including the residence times of fluid flow of the fuel (methane), the oxidant (air), and the cooling fluid (water). As illustrated the resident time of the fuel is about 3.87 minutes at maximum flow and about 15.26 minutes at ¼ of the maximum flow; the resident time of the cooling fluid is about 5.94 minutes at maximum flow and about 23.78 minutes at ¼ of the maximum flow; and the resident time of the oxidant is about 2.37 minutes at maximum flow and about 9.18 minutes at ¼ of the maximum flow.

FIGS. 37-39 illustrate graphs of the injector (e.g. burner head assembly 100) performance when operating at a 375 bpd flow rate with only one injection step (e.g. the first injection step 107), a 1125 bpd flow rate with only one injection step (e.g. the second injection step 108), and a 1500 bpd flow rate with two injection steps (e.g. both the first and second injection steps 107, 108), respectively.

FIG. 40 illustrates gas temperature in the vaporization sleeve 300 versus axial distance from water injection (such as by fluid injection strut 207 and/or fluid injection system 220). As illustrated, the gas temperature drops from about 3,500 degrees Fahrenheit to about 1,750 degrees Fahrenheit instantaneously upon initial injection of fluid droplets into the heated gas. As further illustrated, the gas temperature gradually decreases and eventually is maintained above about 500 degrees Fahrenheit within the vaporization sleeve 300 up to about 25 inches from the initial fluid injection point.

The system 1000 is operable under a range of higher pressure regimes, as opposed to a conventional low-pressure regime, for example, which is managed in part to increase transfer of latent heat to the reservoir. Low pressure regimes are generally used to obtain the highest latent heat of condensation from the steam, however, most reservoirs are either shallow or have been depleted before steam is injected. A secondary purpose of low pressure regimes is to reduce heat losses to the cap rock and base rock of the reservoir because the steam is at lower temperature. However, because this heat loss takes place over many years, in some cases heat losses may actually be increased by low injection rates and longer project lengths.

The system 1000 may be operable in both low pressure regimes and high pressure regimes, and/or in onshore reservoirs at about 2,500 feet deep or greater, near-shore reservoirs, permafrost laden reservoirs, and/or reservoirs in which surface generated steam is generally uneconomic, or not viable. The system 1000 can be used in many different well configurations, including multilateral, horizontal, and vertical wells. The system 1000 is configured for the generation of high quality steam delivered at depth, injection of flue gas, N2 and C02 for example, and higher pressure reservoir management, about 100 psig to about 1,000 psig. In one example, a reservoir which would normally operate at a low pressure regime (e.g. over 40 years) may need to be produced for only 20 years using the system 1000 to produce the same percentage of original oil in place (OOIP). Heat losses to the cap rock and base rock in the reservoir using the system 1000 are therefore also reduced by about 20 years and are far less of an issue.

The system 1000 may also play a beneficial role in low permeability formations where the gravity drainage mechanism may otherwise be impaired. Many formations have a disparity between the vertical permeability and the horizontal permeability to fluid flow. In some situations, the horizontal permeability can be orders of magnitude more than the vertical permeability. In this case, gravity drainage may be hindered and horizontal sweep by steam becomes a much more effective way of producing the oil. The system 1000 can provide the high pressure steam and enhanced oil recovery (EOR) gases that will enable this production scheme.

A summary the potential advantages between high pressure and low pressure regimes using the system 1000 are summarized in Table 1 below.

TABLE 1

Examples of the Advantages of Using the System 1000 with a

High Pressure Regime

Problem
Low Pressure Regime
High Pressure Regime

Heat Losses
One of the reasons
The system 1000 produces

to Base rock
behind using a low
equivalent or larger volumes of oil

& Cap rock
pressure regime is to
in substantially less time. A

of the
use steam more
reservoir operated in low pressure

Reservoir
efficiently due to the
regimes, say over 40 years, may

higher latent heat of
need to be produced only 20 years

steam at low pressure.
to produce the same percentage of

OOIP using the system 1000. The

amount of heat lost per barrel of oil

produced is lower in a higher-

pressure regime due to a shorter

project life, and the projected

steam-oil ratio is lower.

Gas
Lower pressure
Higher pressure & smaller gas

Override,
regimes have higher
volumes used with the system

Breakthrough
reservoir volumes of
1000 reduce or delay

gas which will at some
override/breakthrough. The system

stage override the
1000 high pressure regime will

steam bank and break
have a low reservoir volume of gas

through.
initially, and, as the gas cools, it will

further decrease its volume,

reducing the likelihood or extending

the time frame to override or

breakthrough.

Gas
Dissolved gas
High pressure increases gas

Miscibility
decreases oil viscosity.
dissolution into the oil, therefore

further decreasing viscosity. A

Gas-Oil-Ratio (GOR) as low as 20

can reduce of high viscosity oils by

greater than 90 percent using the

system 1000.

In-situ
Low pressure in-situ
High pressure insures quicker

Combustion
combustion may pose
combustion rates, reducing

some risk of oxygen
likelihood of oxygen breakthrough.

breakthrough to the
High pressure also increases gas

production wells.
phase compression, thereby

reducing its saturation and mobility.

BTU's/lb of
A benefit of low
While pure high pressure steam

condensation
pressure non-
has fewer BTU's/lb of latent heat

and in-situ
condensable gas-free
and a higher temperature, the

steam
steam is that there are
actual heat content and

condensation
more BTU's/lb of heat
condensation temperature are

condensed at low
determined by the steam's partial

pressure. However, at
pressure. Flue (exhaust) gas

low pressure the
allows the steam to condense at a

condensation
lower temperature, deeper in the

temperature is also
reservoir, and accelerates oil

lower, thus reducing or
production.

delaying latent heat

transfer to the oil.

Well Spacing
Low pressure regimes
High pressure drives fluids to the

and primary
generate a larger
production wells, which allows for

production
volume steam chest
wider well spacing for equivalent or

mechanisms
that works primarily
greater oil production rates and

through gravity
lower well capex. In high pressure

drainage. The slower
regimes the drive mechanism plays

drainage mechanism
a stronger role than gravity

means that tight to
drainage. In addition, the high

moderate well spacing
pressure steam-when diluted with

may be required to
flue gas-begins condensing at a

achieve production
about the same temperature as low

goals. As the oil drains
pressure, resulting in a more

over a more extended
effective production means with

timeframe, the gas
delayed breakthrough.

bank has a larger

opportunity to override.

The system 1000 may be operable to inject heated N2 and/or C02 into the reservoirs. N2 and CO2, both non-condensable gas (NCG), have relatively low specific heats and heat retention and will not stay hot very long once injected into the reservoir. At about 150 degrees Celsius, CO2 has a modest but beneficial effect on the oil properties important to production, such as specific volume and oil viscosity. Early on, the hot gasses will transfer their heat to the reservoir, which aids in oil viscosity reduction. As the gases cool, their volume will decrease, reducing likelihood of override or breakthrough. The cooled gases will become more soluble, dissolving into and swelling the oil for decreased viscosity, providing the advantages of a “cold” NCG EOR regime. NCG's reduce the partial pressure of both steam and oil, allowing for increased evaporation of both. This accelerated evaporation of water delays condensation of steam, so it condenses and transfers heat deeper in the reservoir. This results in improved heat transfer and accelerated oil production using the system 1000.

The volume of exhaust gas from the system 1000 may be less than 3 Mcf/bbl of steam, which may have enough benefit to accelerate oil production in a reservoir. When the hot gas moves ahead of the oil it will quickly cool to reservoir temperature. As it cools, the heat is transferred to the reservoir, and the gas volume decreases. As opposed to a conventional low pressure regime, the gas volume as it approaches the production well is considerably smaller, which in turn reduces the likelihood of and delays gas breakthrough. N2 and C02 may breakthrough ahead of the steam, but at that time the gasses will be at reservoir temperature. The hot steam from the system 1000 will follow but will condense as it reaches the cool areas, transferring its heat to the reservoir, with the resultant condensate acting as a further drive mechanism for the oil. In addition, gas volume and specific gravity decrease at higher pressure (V is proportional to 1/P). Since the propensity of gas to override is limited at low gas saturation by low gas relative permeability, fingering is controlled and production of oil is accelerated.

The system 1000 may be operable with as many as 100 injection wells and/or production wells, in which oil production may be accelerated and increased. The system 1000 may be configured to optimize the experience of dozens of world-wide, high-pressure, light- and heavy-oil air-injection projects which produce very little free oxygen, less than about 0.3 percent for example. The preferential directionality of fluid flow through reservoirs may be achieved by restricting production at the production wells that are in the highest permeability regions. Gas production may be limited at each well to help sweep a wider area of the reservoir. Reservoir development planning may use gravity as an advantage where ever possible since hot gases rise and horizontal wells can be used to reduce coning and cusping of fluids in the reservoir.

The system 1000 can produce pure high quality steam with or without carbon dioxide (CO2), and with the addition of hydrogen (H2) to the fuel (methane for example) mixture (CH4+H2), which may materially increase combustion heat. The burner head assembly 100 of the system 1000 can produce high quality steam using methane/hydrogen mixtures with ratios from 100/0 percent to 0/100 percent and everything in between. The system 1000 may be adjusted as necessary to control the effect of any increased combustion heat. The reaction of hydrogen with air (or enriched air) may be about 400 degrees Fahrenheit hotter than the equivalent natural gas reaction. At stoichiometric conditions with air, the combustion products are 34 percent steam and 66 percent nitrogen (by volume) at 4000 degrees Fahrenheit. Water may be added to the operation, or without added water, superheated steam could be generated, unless a large amount of excess N2 is added as a diluent or the system 100 is operated very fuel-lean and with excess oxygen (O2). Other embodiments may include modified fuel injection parameters, and design modifications (ratios and staging of air, water and hydrogen) to mitigate the hotter flame temperatures and associated heat transfer. Corrosion could also be reduced when using hydrogen as a fuel, as essentially the only acidic product (assuming relatively pure H2 and water) would be nitric acid. Corrosion may be reduced further when using oxygen as the oxidizer. The high flame temperature may produce more NOx, but that could be reduced with staged combustion and a different water injection scheme. The reservoir production may be enhanced from strategic use of these co-injected EOR gasses together with (low or high) pressure management regimes.

The system 1000 may use CO2 or N2 as coolants or diluents for the burner head assembly 100 and/or the liner assembly 200. The combination of high quality steam at depth, the ability to manage pressure to the reservoir as a drive mechanism, and improved solubility of the introduced gas (due to the pressurized reservoir) for improved oil viscosity results in substantially accelerated oil production. In high pressure regimes enabled using the system 1000, CO2 is also beneficial even for heavy oils.

The system 1000 can be used in different well configurations, including multilateral, horizontal, and vertical wells and at reservoir depths ranging from as shallow as 0 feet to 1,000 feet, to greater than 5,000 feet. The system 1000 may provide a better economic return or internal rate of return (IRR) for a given reservoir, including permafrost-laden heavy oil resources or areas where surface steam emissions are prohibited. The system 1000 may achieve a better IRR than surface generated steam (using bare tubing or vacuum insulated tubing) due to a number of factors, including: significant reduction of steam losses otherwise incurred in surface steam generation, surface infrastructure, and in the wellbore (increasing with reservoir depth, etc.); higher production rates from higher quality, higher pressure steam injected together with reservoir-specific EOR gasses (and optionally in-situ combustion) to generate more oil, faster; and associated savings in energy costs/bbl, water usage and treatment/bbl, lower emissions, etc. The system 1000 may be operable to inject steam having a steam quality of 80% or greater at depths ranging from 0 feet to about 5000 feet and greater.

One advantage of the system 1000 is the maintenance of high pressure in the reservoir, as well as the ability to keep all gases in solution. The system 1000 can inject as much as 25 percent CO2 into the exhaust stream. With the combination of high pressure and low reservoir temperatures, the CO2 can enter into miscible conditions with the in-situ oil, thereby reducing the viscosity ahead of the steam front. Recovery factors as high as 80 percent have been seen after ten years in modeling of 330 foot spacing steam assisted gravity drainage (SAGD) wells plus drive wells in reservoirs containing 126,000 centipoise oil. Increasing the spacing to 660 feet may yield recovery factors of 75 percent after 22 years.

The system 1000 may work with geothermal wells, fireflooding, flue gas injection, H2S and chloride stress corrosion cracking, etc. The system 1000 may include a combination of specialized equipment features together with suitable metallurgies and where necessary use of corrosion inhibitors. Corrosion at the production wells can be controlled in high-pressure-air injection projects by the addition of corrosion inhibitors at the producers.

The system 1000 may be operable at relatively high pressures, greater than 1,200 psi in relatively shallow reservoirs, assuming standard operating considerations such as fracture gradients, etc. To achieve the high pressure in shallow reservoirs, throttling the production well outlet may be required to obtain the desired backpressure.

The system 1000 may be operable using clean water (drinking water standards or above) and/or brine as a feedwater source, while avoiding potential issues from scaling, heavy metals, etc. within the system 1000 and in the reservoir.

The system 1000 may be operable to maintain higher reservoir pressures that offset the lower temperature of steam mixed with NCGs. The addition of NCG to steam will lower the temperature at which the steam condenses at higher pressures by 50-60 degrees Fahrenheit because the partial pressure of water is lower. Therefore, the steam temperature in the system 1000 is approximately the same as the steam temperature in a lower pressure regime without NCG. The temperature is lowered, but the steam does not condense as easily. Additionally the partial pressure of oil is lowered and more oil evaporates as well. Both of these help increase oil recovery. Additionally, the presence of gases helps to swell the oil, forcing some oil out from the pore spaces and again increasing recovery. By operating the system 1000 and the reservoir at a high pressure you can combine the benefits of miscible flooding in the cooler parts of the reservoir with steam flood following after. Also, by operating at a high pressure there are two mechanisms to reduce the viscosity of heavy oil. The first, which accelerates oil production, is higher Gas-Oil-Ratios and lower oil viscosity at temperatures up to approximately 150 degrees Celsius. The second is the traditional reduction in oil viscosity at higher temperature.

FIGS. 41A, 41B, and 41C illustrate examples of the composition and flow rate of exhaust gases that can be generated using the system 1000.

FIG. 42 illustrates an example of the operational metrics of the system 1000 compared to that of surface steam in a reservoir at a depth of about 3500 feet.

FIGS. 43A, 43B, and 43C illustrate examples of the BTU contribution from the delivered steam and exhaust gases using the system 1000 compared to delivery of steam from the surface.

A method of recovering hydrocarbons from a reservoir comprises supplying a fuel, an oxidant, and a fluid to a downhole system; flowing water to the system at a flow rate within a range of about 375 barrels per day to about 1500 barrels per day; combusting the fuel, oxidant, and water to form steam having about an 80 percent water vapor fraction; maintaining a combustion temperature within a range of about 3000 degrees Fahrenheit to about 5000 degrees Fahrenheit; maintaining a combustion pressure within a range of about 300 PSI to about 2000 PSI; and maintaining a fuel injection pressure drop in the system above 10 percent.

While the foregoing is directed to embodiments of the invention, other and further embodiments of the invention may be implemented without departing from the scope of the invention, and the scope thereof is determined by the claims that follow.

	Number	Date	Country
	61311619	Mar 2010	US
	61436472	Jan 2011	US

DOWNHOLE STEAM GENERATOR AND METHOD OF USE

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CPC

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Abstract

Description

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