Patent Grant
9422797
1. Field of the Invention
Embodiments of the invention 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 3,000 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 a permafrost layer that may extend as deep as 1800 feet. Steam cannot be injected though the permafrost layer 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 steams 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 employed. 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 generator designs.
Embodiments of the invention relate to a downhole steam generation apparatus. In one embodiment, a downhole steam generation apparatus for injecting a heated fluid mixture into a reservoir may include an injection section including a housing, an injector element disposed in the housing, and an injector plate coupled to the housing. The apparatus may include a combustion section including a body coupled to the housing and forming a combustion chamber, wherein the body includes a unitary annulus disposed therethrough. The apparatus may further include an evaporation section including a nozzle coupled to the body, wherein the nozzle is operable to inject fluid droplets into the combustion chamber in a direction away from the injection section.
In one embodiment, a method for injecting a heated fluid mixture into a reservoir may include positioning an apparatus in a wellbore, wherein the apparatus includes a liner having a chamber; supplying a fuel, an oxidant, and a fluid to the apparatus; combusting the fuel and the oxidant in the chamber while flowing the fluid through an annulus disposed through the liner, thereby heating the fluid and cooling the liner; injecting droplets of the heated fluid into the chamber co-flow to injection of the fuel and oxidant into the chamber; and evaporating the droplets by combustion of the fuel and the oxidant to produce steam.
In one embodiment, a method for injecting a heated fluid mixture into a reservoir may include supplying a first fluid and a second fluid to an injector body; injecting the first fluid and the second fluid from the injector body to a combustion chamber for combustion of the first and second fluids, wherein the combustion section includes a chamber, a liner surrounding the chamber, and a unitary annulus disposed through the liner; supplying a third fluid through the unitary annulus of the liner, thereby cooling the liner; heating the fluid supplied through the unitary annulus by combustion of the first and second fluids in the combustion chamber; injecting droplets of the heated fluid from the unitary annulus into the combustion chamber in a direction parallel to the flow of the first and second fluids, thereby evaporating the droplets; injecting the combusted first and second fluids and the evaporated droplets into the reservoir; and injecting a nanocatalyst into the reservoir.
In one embodiment, a downhole steam generation apparatus for injecting a heated fluid mixture into a reservoir may include an injection section having a housing, an injector element disposed in the housing, and an injector plate coupled to the housing. The apparatus may include a combustion section having a body coupled to the housing that forms a combustion chamber. The body may include a unitary annulus disposed therethrough. The apparatus may include an evaporation section having a nozzle coupled to the body. The nozzle is operable to inject fluid droplets into the combustion chamber in a direction away from the injection section.
The unitary annulus may be in fluid communication with the nozzle. The evaporation section may further include a conduit coupled to the nozzle and the body. The unitary annulus may be in fluid communication with the nozzle via the conduit. The nozzle may be operable to inject fluid droplets into the combustion chamber in a direction radially outward toward the body.
In one embodiment, a method for injecting a heated fluid mixture into a reservoir may comprise positioning an apparatus in a wellbore, wherein the apparatus includes a liner having a chamber; supplying a fuel, an oxidant, and a fluid to the apparatus; combusting the fuel and the oxidant in the chamber while flowing the fluid through an annulus disposed through the liner, thereby heating the fluid and cooling the liner; injecting droplets of the heated fluid into the chamber co-flow to injection of the fuel and oxidant into the chamber; and evaporating the droplets by combustion of the fuel and the oxidant to produce steam.
The fuel may include at least one of synthesis gas and hydrogen, and the oxidant may include at least one of dioxide, pure oxygen, and enriched air. The method may further comprise flowing the heated fluid through a conduit that radially extends into the chamber. The method may further comprise injecting droplets of the heated fluid into the chamber using a nozzle coupled to the conduit. The steam may include superheated steam.
In one embodiment, a method for injecting a heated fluid mixture into a reservoir may comprise supplying a first fluid and a second fluid to an injector body; injecting the first fluid and the second fluid from the injector body to a combustion chamber for combustion of the first and second fluids, wherein the combustion section includes a chamber, a liner surrounding the chamber, and a unitary annulus disposed through the liner; supplying a third fluid through the unitary annulus of the liner, thereby cooling the liner; heating the fluid supplied through the unitary annulus by combustion of the first and second fluids in the combustion chamber; injecting droplets of the heated fluid from the unitary annulus into the combustion chamber in a direction parallel to the flow of the first and second fluids, thereby evaporating the droplets; injecting the combusted first and second fluids and the evaporated droplets into the reservoir; and injecting a nanocatalyst into the reservoir.
The first fluid may be an oxidant comprising at least one of dioxide, pure oxygen, and enriched air. The second fluid may be a fuel comprising at least one of synthesis gas and hydrogen. The method may further comprise generating superheated steam by evaporation of the droplets. The method may further comprise recovering gas hydrates from the reservoir. The method may further comprise upgrading hydrocarbons disposed in the reservoir using the combusted first and second fluids, the evaporated droplets, and the nanocatalyst injected into the reservoir. The nanocatalyst may be injected into the reservoir simultaneously with the combusted first and second fluids and the evaporated droplets.
In one embodiment, a method of optimizing a burner located in a wellbore may comprise supplying a fuel and an oxidant to the burner; combusting the fuel and the oxidant, thereby forming a combustion flame; and controlling a size, a shape, and an intensity of the flame to optimize the burner based on wellbore conditions.
In one embodiment, a method of selecting combustion chamber parameters including but not limited to length, diameter and number may be provided to optimize heat transfer to the walls and optimize complete combustion.
In one embodiment, a method of selecting water injector parameters including the number, design, droplet size distribution and spray geometry may be provided to avoid flame quenching, complete evaporation in a distance commensurate with the application requirements, provide wall wetting to avoid overheating and minimize deposit formations on the walls of the combustion chamber and downstream components.
In one embodiment, a method of controlling heat transfer in a burner may comprise providing a burner having an injector head and a combustion chamber; combusting reactants in the combustion chamber; supplying water through one or more cooling passages disposed in the walls of the combustion chamber; and varying one or more of: reactants in the burner, injector head design, combustion chamber geometry, water flow rate, fluid velocity swirl and turbulence, cooling passage geometry, number of cooling passages, wall characteristics to induce turbulence, inserts in the cooling passages, and direction of flow within the cooling passages, to thereby minimize the formation of at least one of steam and gas bubbles in the cooling passages of the combustion chamber.
So that the manner in which the above recited features of the invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.
Embodiments of the invention generally relate to an apparatus and method of use of a downhole steam generator (DHSG). As set forth herein, embodiments of the invention will be described as they relate to a DHSG and heavy oil reservoirs. It is to be noted, however, that aspects of the invention are not limited to use with a DHSG, but are applicable to other types of systems, such as other downhole mixing devices. It is to be further noted, however, that aspects of the invention are not limited to use in the recovery of heavy oil, but are applicable to use in the recovery of other types of products, such as gas hydrates. To better understand the novelty of the apparatus of the invention and the methods of use thereof, reference is hereafter made to the accompanying drawings.
In operation, the DHSG 10 is operable to generate heat within a heavy oil reservoir by burning a fuel and an oxidant supplied from the surface. The viscosity of heavy oil in the reservoir may be reduced by injecting one or more fluids and/or solvents, including but not limited to, water, partially or fully saturated steam, superheated steam, oxygen, air, rich air, natural gas, carbon dioxide, carbon monoxide, methane, nitrogen, hydrogen, hydrocarbons, oxygenated-hydrocarbons, or combinations thereof, using the DHSG 10 or separately from the DHSG 10, into the reservoir. In one embodiment, one or more of these fluids may be combusted in the DHSG 10 to produce a stream of heated water, partially or fully saturated steam, or superheated steam, which may also include carbon dioxide, carbon monoxide, natural gas, methane, nitrogen, hydrogen, hydrocarbons, oxygenated-hydrocarbons, air, rich air, and/or oxygen, and which will be injected into the reservoir. In one embodiment, nanocatalysts may also be dispersed into the reservoir independently or in combination with the combustion products injected into the reservoir using the DHSG to further facilitate recovery of hydrocarbons. In one embodiment, nanocatalysts may be injected into the reservoir with the combustion products using the DHSG to further facilitate recovery of hydrocarbons. U.S. Pat. No. 7,712,528 and co-pending U.S. patent application Ser. No. 12/767,466 are herein incorporated by reference and describe exemplary embodiments of utilizing nanocatalysts for the recovery of hydrocarbons which may be used with the embodiments described herein. The heavy oil in the reservoir may then be recovered by a variety of ways known in the art, such as by gas lift.
To generate combustion, the DHSG 10 may utilize natural gas as a fuel. In one embodiment, the DHSG 10 may utilize an oxygen and carbon dioxide mixture as an oxidant. In one embodiment, the oxidant stream may include a small percentage of nitrogen, such as about 5 percent. In one embodiment, synthesis gas may be used as the fuel. In one embodiment, the oxidant may include dioxide. In one embodiment, a mixture of oxygen and nitrogen may be used as the oxidant. In one embodiment, any gaseous or liquid fuel may be used, which may include natural gas, synthesis gas, low BTU gas derived from coal or other fuels, such as hydrogen, etc. In one embodiment, the oxidant may be pure oxygen or oxygen diluted with other fluids, such as carbon dioxide, carbon monoxide, hydrogen, nitrogen, and/or steam. In one embodiment, the oxidant may be air or enriched air.
In one embodiment, the oxygen and carbon dioxide mixture may be used to help control combustion, particularly to control flame temperature and to avoid extremely high flame temperatures. This mixture may be mixed at the surface and supplied in a single conduit to the DHSG 10. In one embodiment, the fuel, the oxidant, and/or any other fluids, such as water, may be supplied by separate conduits to the DHSG 10 as will be further described below.
The DHSG 10 may be operable to adjust flame temperature by changing the concentration of diluents supplied to the flame. Any non-reacting diluent may be used to facilitate adjustment of the flame temperature when supplied separately to the DHSG 10 and/or mixed with either the fuel or oxidant streams or both. In one embodiment, the carbon dioxide flow rate to the DHSG 10 can be adjusted to control flame temperature. The carbon dioxide may be mixed with the fuel, the oxidant, or both. In one embodiment, a diluent such as argon may be supplied to the DHSG 10 separately and/or mixed with either the fuel or oxidant streams or both.
As illustrated in
The DHSG 10 may be formed from corrosion resistant materials, for example, to avoid corrosion by sulfur compounds for the components exposed to flame and combustion products. Particular components of the DHSG 10 may be formed from metals, such as steel, copper, and cobalt, from metal alloys, such as stainless steel, nickel-copper, and ceramic dispersion coppers, and metal alloys from brands such as Monel, Inconel, and Haynes alloys. In one embodiment, Monel 400 or 500 may be used for the DHSG components exposed to gaseous oxygen. In one embodiment, Haynes 188, 230, and/or 556 may be used for the DHSG 10 components subjected to a corrosive environment. In one embodiment, the water exposed components of the DHSG 10 may be formed from copper alloys, OFHC, GlidCop, GRCop84, AMZirc, beryllium copper, high thermally conductive materials, and/or ductile materials. In one embodiment, the combustion and/or evaporation sections 30 and 40 of the DHSG 10 may be formed from cobalt alloys, Haynes 188, Alloy 25, creep resistant materials, corrosion resistant materials, and/or materials having high strength at high temperatures. Higher temperature metals may facilitate cooling of the DHSG 10, and increase its thermal control and efficiency, thereby reducing stresses in the DHSG 10 components caused by extreme temperatures and increasing conduction paths from the heated surfaces to the cooling channels, as described herein.
The injector body 25 and the injector plate 29 are surrounded by the housing 15. The injector body 25 and/or the injector plate 29 may be coupled to a liner 33, such as a housing or body, of the combustion section 30. An annulus 19 may be formed between the housing 15 and the liner 33. The liner 33 may be formed from a single structural component. In one embodiment, the liner 33 may include multiple segments coupled together to form a single structure. In one embodiment, the liner 33 may include an inner diameter of about 3 inches. In one embodiment, the liner 33 may include an inner diameter in a range of about 2 inches to about 8 inches. At a first end, the liner 33 has a flanged end that is adapted to sealingly engage a lower portion of the injector body 25, such that fluids flowing through the injector elements 27 exit into the combustion chamber 35 of the liner 33. At a second end, the liner 33 may also have a flanged end that is in fluid communication with the evaporation section 40 and may be coupled to a tailpipe 50. In alternative embodiments, the ends of the liner 33 may include other means of connection to secure the components of the DHSG 10 together and with other downhole components to facilitate insertion into the wellbore. In one embodiment, the tailpipe 50 is integral with the housing 15. In one embodiment, the tailpipe 50 may be adapted to engage a downhole tool, such as a packer.
The liner 33 may further include an annular structure with a hollow body that forms the combustion chamber 35. The annular structure may have one or more holes or channels 37 circumferentially located about the wall of the annular structure, also surrounding the combustion chamber 35. The channels 37 extend the longitudinal length of the liner 33. In an alternative embodiment, the liner 33 may include a unitary annulus disposed through the body of the liner 33, surrounding the combustion chamber 35, and in fluid communication with the injection section 20 and the evaporation section 40, through which fluid may be directed. In an alternative embodiment, the liner 33 may include a narrow annulus having a spider portion or other similar device to help direct flow of fluids through the annulus. The spider portion may be placed over the inner wall of the liner and then the outer wall of the liner may be placed over the assembled inner wall and the spider portion, thereby forming one or more channels through the liner. In one embodiment, the channels 37 may include a circular shape. A fluid may enter an upper manifold in fluid communication with the channels 37 near the first end of the liner 33 adjacent the injection section 20 and may exit the channels 37 near the second end of the liner 33 adjacent the evaporation section 40. The channels 37 may empty into a lower manifold 39 disposed in the second end of the liner 33, which supplies the fluid to the evaporation section 40. In one embodiment, the lower manifold 39 may be disposed within the flanged end of the liner 33. As stated above, a similar manifold may be disposed in the first end of the liner 33, which supplies the fluid to the channels 37. In one embodiment, liquid water is supplied to the channels 37 of the liner 33, wherein the water is purified to less than one part per million of total dissolved solids. The chemistry of the liquid water may be controlled to prevent scaling in the channels 37 of the liner 33.
As energy or heat is generated and is released from the combustion reactions generated in the combustion chamber 35, the fluid supplied through the channels 37 of the liner 33 may act as a cooling agent and a heat transfer mechanism, to control and reduce the temperature of the liner 33. Fluids may be introduced into the channels 37 at its coolest temperature nearest the injection section 20 and the energy generated by the combustion reaction in the combustion chamber 35 may be used to heat the fluid as it travels through the channels 37 along the length of the liner 33 away from the injection section 20. In one embodiment, a fluid directed through the channels 37 of the liner 33 may be heated to a temperature below the boiling temperature of the fluid. In one embodiment, the DHSG 10 may be configured to heat fluid as it is directed through the channels 37 of the liner 33, while preventing steam generation in the channels 37. In one embodiment, fluid may alternately flow from a point furthest away from the injection section 20 to a point closest to the injection section to maintain temperature control of the liner 33.
The channels 37 of the liner 33 may be in communication with the evaporation section 40 via the lower manifold 39. The evaporation section 40 may include one or more conduits 43 that are in fluid communication with the manifold 39 of the liner 33. The conduits 43 may radially extend from the liner 33 and intersect at a compartment 47, which may be centrally located within the combustion chamber 35. The compartment 47 may be coupled to one or more nozzles 45 (shown in
An intermediate plenum may be formed within the injector body 25 for receiving the fuel supplied from the fuel supply line 22B. The top cover 23 and the inner plate 26 may sealingly enclose the intermediate plenum. The fuel may be supplied to the intermediate plenum of the injector body 25, via the fuel supply line 22B, through an opening in the injector body 25. In an optional embodiment, a bottom plenum may optionally be formed within the injector body 25 for receiving one or more fluids, such as partially or fully saturated steam, water, carbon dioxide, or combinations thereof via one or more feed ports 28 for mixing with the fuel. In one embodiment, the one or more fluids may be used as cooling fluids to cool the components of the DHSG 10, such as the injection section 20 and/or combustion section 30. The injector plate 29 may be coupled to the base of the injector body 25, thereby sealingly enclosing the bottom plenum. In one embodiment, the injector plate 29 may be bolted to the injector body 25, as shown in
The injector elements 27 may extend from the top plenum, through the intermediate and bottom plenums, and through the injector plate 29, such that the plenums are in fluid communication with the combustion chamber 35. The injector elements 27 may be coupled to the inner plate 26, the injector body 25, and the injector plate 29. The injector elements 27 may be configured to control mixing of the fuel, the oxidant, and/or any other fluid supplied through the injector elements 27 to control flame shape while achieving essentially complete combustion. The fluid mixing rates may be adjusted to control the size of the combustion flame.
In one embodiment, the conduits may include eight conduits 43 radially disposed around the compartment 47. In one embodiment, liquid water may be heated by heat generated from the combustion flame as it travels through the channels 37 and may exit the channels 37 of the liner 33 into the conduits 43. In one embodiment, liquid water may be injected at a high velocity into the heated combustor exhaust and boiled via droplet evaporation, thereby providing partially or fully saturated steam or superheated steam generation. In one embodiment, liquid water may be evaporated to about a range of 90 percent to 95 percent steam quality at the point of injection into the oil reservoir. In one embodiment, liquid water may be evaporated to about a range of 80 percent to 100 percent steam quality at the point of injection into the oil reservoir. In one embodiment, liquid water may be evaporated to about a range of about 95 percent to about 99 percent steam quality at the point of injection into the heavy oil reservoir.
In one embodiment, the number of droplet injectors, type of droplet injectors, spray pattern, and direction of spray of the evaporation section may be adjusted to provide rapid droplet evaporation and combustion product cooling. The evaporation section facilitates an equilibrium steam quality of the combustion products. In one embodiment, the evaporation section may facilitate fluid droplets impinging on the walls of the combustion section downstream of the injection section so that the wall temperature of the combustion section remains close to the fluid droplet temperature.
In an alternative embodiment, the DHSG 10 may include an injection section that supplies the fuel and the oxidant in such a manner that the fluids mix in the combustion chamber and provides a stable combustion flame having a shape that fits within the combustion chamber volume, during the startup and shutdown of the DHSG 10, as well as during the full operating range of pressures and stoichiometry. The DHSG 10 may include a number of alternate injection sections that produce diffusion flames, partially premixed diffusion flames, and premixed flames. Each of these flame types may be utilized with the DHSG 10, including stable flames of adequate size during the operation of the DHSG 10.
In one embodiment, the DHSG 10 may include a diffusion flame injection section. The fuel and the oxidant are injected into the combustion chamber as separate fluid streams. The diffusion flame injection section includes injector elements that are operable and arranged to provide controlled mixing of the fluids into the combustion chamber, thereby producing a combustible mixture. The diffusion flame injection section provides a combustion flame that is stabilized by controlling the injection velocities of the fluids into the combustion chamber, such as maintaining low injection velocities of the fluids relative to the flame speed, and/or by recirculating hot combustion products back to the base of the flame, such as by injecting the fuel and/or the oxidant with a swirl that produces an axisymmetric recirculation zone or by generating a recirculation zone in the wake behind a bluff body or the walls of the injectors themselves. The combustion flame shape may be adjusted by controlling the rate of the fuel/oxidant mixing. In general, rapid mixing produces a compact high intensity combustion flame with high radiative heat transfer in contrast to slow mixing which produces a larger low intensity combustion flame with lower radiative heat transfer. By varying the swirl and the injection velocities, the combustion flame shape can be adjusted to fit the combustion chamber. In one embodiment, the DHSG 10 may include one or more injection sections/elements to provide additional combustion flame shaping flexibility, such as by operating less than all of the injection sections/elements during lower operating ranges or by reducing the range of firing rates for each individual injection section/elements to provide enhanced combustion flame stability and control.
A method of utilizing the DHSG 10 may include supplying natural gas and an oxygen and carbon dioxide mixture to an injector body of the DHSG 10. The mixture may be mixed at the surface and supplied to the DHSG 10 in a single conduit and the fluids may be mixed in the injector body. The DHSG 10 may be positioned in a first well for use as an injection well. The method may further include directing the fluids through one or more injector elements that are in fluid communication with the combustion chamber. The injector elements may be coupled to the injector body and disposed in a circular array. The injector elements may include a body and a sleeve surrounding the body. The method may further include directing the mixture from a first plenum of the injector body, through a channel of the body of an injector element, and injecting the mixture into the combustion chamber. The method may further include directing the natural gas from a second plenum of the injector body, and optionally directing a diluting or cooling fluid, such as water, partially or fully saturated steam, oxygen, air, enriched air, nitrogen, hydrogen, and/or carbon dioxide, from an optional third plenum of the injector body, through the sleeve of the injector element, such that the fluids form a swirling pattern as they are directed through the sleeve. The method may further include injecting the fluids into the combustion chamber with the mixture. The method may further include providing an ignition flame from an igniter through an igniter port disposed through the injector body to combust the mixture of fluids injected into the combustion chamber. The method may further include igniting the mixture of fluids in the combustion chamber, thereby generating a combustion flame and combustion products. The swirling pattern may help maintain a stabilized combustion flame within the combustion chamber. The fluids flowing through the combustion section may provide cooling of the DHSG 10, and the temperature of the DHSG 10 may be controlled by carbon dioxide dilution. In one embodiment, additional cooling passages may be provided in the combustion section. The method may further include supplying a fluid, such as water, through one or more channels of a liner, wherein the liner surrounds the combustion chamber. The method may further include heating the fluid as it travels through the channels by the combustion reactions in the combustion chamber, wherein the fluid cools the liner. The combustion flame may transfer heat to the liner walls by radiative and convective heat transfer. The method may further include injecting the heated fluid from the channels into the combustion chamber, in a droplet form, via one or more conduits in fluid communication with the channels, and boiling the heated fluid via droplet evaporation, wherein the combustion flame and products evaporate fluid droplets of the heated fluid injected into the combustion chamber. The fluid may cool the combustion products. The method may further include injecting the combustion products and the evaporated fluid droplets into an oil reservoir to upgrade and/or reduce the viscosity of hydrocarbons in the oil reservoir. The method may further include recovering at least the upgraded and/or less viscous hydrocarbons from a second well that is located adjacent to the first well in which the DHSG is located. The second well may be utilized as a production well. The production well may include one or more pressure control devices located at the surface to control the back pressure on the oil reservoir. In one embodiment, a choke valve may be used to maintain and/or control the pressure and/or flow of fluids recovered from the oil reservoir via the production well.
The DHSG 10 may be operable under pressure conditions in a range of about 800 psi to about 1,600 psi. The DHSG 10 may be operable under pressure conditions in a range of about 500 psi to about 2,000 psi. In one embodiment, the DHSG 10 is operable under a pressure range of about 800 psi to about 2,000 psi. In one embodiment, the DHSG 10 may be operable under pressure conditions in a range of about 100 psi to about 4,000 psi. In one embodiment, the DHSG 10 may be operable under pressure conditions up to about 10,000 psi. In one embodiment, the DHSG 10 may also be operable under a nominal flame temperature in a range of about 3,200 degrees Fahrenheit to about 3,450 degrees Fahrenheit. In one embodiment, the DHSG 10 may also be operable under a nominal flame temperature in a range of about 2,500 degrees Fahrenheit to about 5,500 degrees Fahrenheit. In one embodiment, the DHSG 10 is operable under a nominal flame temperature in a range of about 3,000 degrees Fahrenheit to about 3,500 degrees Fahrenheit. In one embodiment, the DHSG 10 may be operable at internal pressures up to 1,800 psi and exhaust a heated fluid mixture at up to 600 degrees Fahrenheit. In one embodiment, the DHSG 10 may be operable to exhaust a heated fluid mixture at a temperature within a range of about 500 degrees Fahrenheit to about 800 degrees Fahrenheit. In one embodiment, the DHSG 10 may be operable to exhaust a heated fluid mixture at a temperature within a range of about 250 degrees Fahrenheit to about 800 degrees Fahrenheit. In one embodiment, the DHSG 10 may be operable to exhaust a heated fluid mixture at a temperature of about 600 degrees Fahrenheit. In one embodiment, the DHSG 10 may be operable to limit metal temperatures to below 1,000 degrees Fahrenheit.
The DHSG 10 may be configured to generate a fluid having a steam quality in a range of about 75 percent to about 100 percent. In one embodiment, the DHSG 10 may be configured to generate a fluid having about a 90 percent to about a 95 percent steam quality. The DHSG 10 may also be configured to provide a mass flow rate of a fluid, such as partially saturated, fully saturated, or superheated steam, in a range of about 400 barrels per day (bbd) to about 1500 barrels per day. In one embodiment, the DHSG 10 may be configured to provide a mass flow rate of a fluid, such as partially saturated, fully saturated, or superheated steam, at about 1500 bbd under a pressure condition of about 1600 psi. Finally, the DHSG 10 may be configured to have a minimum operating life of about 3 years.
The DHSG 10 may be configured to inject a mixture of fluids into a formation to heat the formation and to facilitate the recovery of hydrocarbons from the formation, such as by reducing the viscosity of heavy oil located in the formation. In one embodiment, the mixture may comprise from about 18 percent to about 29 percent of carbon dioxide by volume. In one embodiment, the mixture may comprise from about 10 percent to about 30 percent of carbon dioxide by volume. In one embodiment, the mixture may comprise from about 1 percent to about 40 percent of carbon dioxide by volume. In one embodiment, the mixture may comprise about 0.5 percent or about 5 percent of oxygen by volume. In one embodiment, the mixture may comprise from about 0.5 percent to about 5 percent of oxygen by volume. The mixture may be injected into the formation at a pressure of about 900 psi, 1200 psi, or 1600 psi. The mixture may be injected into the formation at a mass flow rate of about 400 bbd, 800 bbd, 1200 bbd, or 1500 bbd.
Also illustrated is an injector plate 118 coupled to and sealingly engaged with the flanged end 111 of the housing for directing the combustion fluids into the combustion section 120 of the DHSG 100. The injector plate 118 may also be operable for supporting one or more injector elements and an igniter (further described below). The injector plate 118 may include first injector element ports 161, second injector element ports 162, and an igniter port 171. The first injector element ports 161 may be equally spaced apart forming a circular pattern adjacent the outer diameter of the injector plate 118. The second injector element ports 162 may also be equally spaced apart forming a circular pattern adjacent the center of the injector plate 118, surrounded by the first injector element ports 161. The igniter port 171 may be disposed in the center of the injector plate 118 and surrounded by the first and second injector element ports 161 and 162.
Illustrated in
Illustrated in
In one embodiment, the feed tubes 140 and/or the igniter housing 170 may be formed from a metallic material, such as a nickel-copper alloy, such as Monel. In one embodiment, the manifolds 112 and 113 may be formed from a metallic material, such as a nickel-cobalt alloy, such as Haynes 188. In one embodiment, the upper section 117 of the housing may be formed from a metallic material, such as a nickel-copper alloy, such as Monel. In one embodiment, the lower section 116 of the housing may be formed from a metallic material, such as a nickel-cobalt alloy, such as Haynes 188. In one embodiment, the injector elements 160 and 165 may be formed from a metallic material, such as a nickel-copper alloy, such as Monel.
The DHSG 10 and 100 described above may include multiple combustion chambers. In one embodiment, the multiple combustion chambers may be positioned in series or in a parallel configuration. Each combustion chamber may share a liner with one or more other combustion chambers and/or may include a single liner. In one embodiment, the DHSG 10 and 100 may include a variety of multiple injection, combustion, and evaporation section configurations described above.
In one embodiment, one or more fluids, including but not limited to water, natural gas, oxygen, air, rich air, carbon dioxide, nitrogen, hydrogen, inert gases, hydrocarbons, oxygenated-hydrocarbons, and combinations thereof may be supplied from the surface to the DHSG via one or more tubular members, such as umbilicals. The one or more fluids may be supplied to the DHSG simultaneously and/or in a staged fashion depending on the desired operation. In one embodiment, the one or more fluids, including but not limited to carbon dioxide, nitrogen, hydrogen, and/or inert gases may be used to control (lower) the temperature of the DHSG or a liner/combustion chamber of the DHSG, transmit incremental heat from the DHSG to an oil reservoir, and improve oil recovery by dissolving into the oil, thereby upgrading the oil and decreasing its viscosity. In one embodiment, carbon dioxide, nitrogen, and/or other inert gases may be simultaneously injected with steam using the DHSG. In one embodiment, hydrogen may be simultaneously injected with steam using the DHSG. In one embodiment, the DHSG may be configured to inject other materials (liquids, gases, solids) that complement steam and provide in-situ upgrading. In one embodiment, the other materials may include nanocatalysts, surfactants, solvents, etc. In one embodiment, the DHSG may be operable to maintain and/or adjust the pressure and flow rates of fluids/materials flowing through the DHSG in real time to optimize reservoir production and process economics.
In one embodiment, steam, excess oxygen (including air or enriched air), carbon dioxide, nitrogen, and/or hydrogen may be simultaneously injected into the oil reservoir via the DHSG to generate incremental heat and a controlled independent steam front. In-situ oxidation (combustion) of the oil reservoir's bypassed residual oil may generate more heat and more steam downhole. The DHSG may be configured to generate and manage stable in-situ oxidation through the addition of surplus oxygen and external high pressure steam. The large, stable incremental steam front may yield more heat for more oil combustion. In one embodiment, surplus pressurized oxygen and high quality steam may be injected directly to the oil reservoir using the DHSG. Residual oil that may be left behind the initial steam front may support and accelerate combustion of the surplus oxygen, thereby creating a combustion front. The combustion front may increase the temperature of the steam front, and may heat and/or vaporize water present in the reservoir to generate another large, stable steam front which can accelerate oil production. In one embodiment, the initial steam front may heat the oil ahead of the in-situ combustion to ensure that all surplus oxygen reacts in the reservoir and prevent non-combusted oxygen breakthrough into the production wells, thereby improving safety and decreasing potential corrosive effects to infrastructure.
In one embodiment, the DHSG may be used to combust natural gas and thereby produce carbon dioxide, which is injected into and remains in the oil reservoir (sequestration). In one embodiment, the carbon dioxide produced from a production well may be recycled and reused for DHSG cooling and/or enhanced reservoir production. In one embodiment, the carbon dioxide produced from a production well may be sold and/or used for other types of operations.
In one embodiment, the reservoir pressure may be maintained and controlled at the production well using a pressure control device to “throttle” the produced fluid stream to maintain “back pressure”. The reservoir pressure may also be maintained and controlled using the DHSG by injecting fluids at the injection well. The use of two pressure control points may provide better reservoir management, promote gas solubility in the oil for less viscous oil and accelerated recovery, improve the gas-oil-ratio (GOR) which in turn reduces the oil's viscosity ahead of the steam front and accelerates production, prevents premature gas production, which detracts from oil production and may increase operating costs if not managed. In addition, gas injection reduces the partial pressure of steam and causes it to condense deeper in the oil reservoir, so that heat transfer improves and oil production increases. In one embodiment, the recovered fluids at the production well may be controlled (e.g. limited) so that the injection pressure is maximized within the oil reservoir formation. Maintaining a high reservoir pressure may provide high-flowing back pressure on the production well, high solubility of carbon dioxide in the cold oil ahead of the steam front, and high condensation temperature of the steam which in turn assures high solubility of water in the hot oil. This combination of effects reduces the oil's viscosity, limits or prohibits oxygen breakthrough, and increases pyrolysis of the oil in the reservoir thereby increasing its API gravity and reducing its sulfur content.
In one embodiment, one or more tubular members or bundled conduits, such as umbilicals, may be used to transmit electric power, fluids, gases and/or communication signals from surface equipment to one or more components of the DHSG. In one embodiment, the tubular members may include wires and/or pipes bundled within a larger reinforced encasement, including insulation. In one embodiment, one or more umbilicals may be used to deliver water, oxygen, nitrogen, carbon dioxide, fuel, and/or other gases and fluids from surface equipment to the DHSG. In one embodiment, the umbilicals may include control lines from surface equipment to the DHSG.
In one embodiment, one or more (automated) control systems and/or sensors may be used to provide real time control/monitoring of the DHSG and the reservoir production. A control system may be operable to reduce the effects of lag times, and monitoring and managing DHSG operations several hundreds and/or thousands of feet below the surface control elements. The control system may include all aspects of safe, reliable operations across all potential operating conditions and anomalies, including automatic shut down of the DHSG as required. In one embodiment, one or more components including flowmeters, high temperature fiber optic monitoring (to monitor steam distribution in real time), high temperature gauges and valves for downhole monitoring, and high pressure and temperature sensors, thermocouples, and transducers may be used with the DHSG to measure and monitor one or more operational characteristics.
In one embodiment, one or more support devices, such as packers, may be used to support DHSG equipment to a specified position in the wellbore casing or tubular and to provide a pressure seal. The packers may have a mandrel so that tubing can be run within the length of the packer. In one embodiment, one or more packers may be used to support the weight of the DHSG, tubulars and the tailpipe. The output from the tailpipe of the DHSG may be disposed through the mandrel in the packer to be injected into the oil reservoir. In one embodiment, the packer may be operable at high temperatures of up to 680 degrees Fahrenheit.
In one embodiment, one or more artificial lift systems may be used with the DHSG system to provide incremental pumping power to lift fluids from the reservoir, including oil, water, sand, etc. to the surface for separation. An artificial lift system may be used with a light oil diluent stream (which is pumped into the production well, resulting in a lower viscosity blended oil mixture) for easier pumping. Artificial lift systems may include progressive cavity pumps and electrical submersible pumps.
In one embodiment, a variety of other fit-for-purpose equipment and services may be used with the DHSG system, including but not limited to specific drilling fluids (SAGD drilling fluids), well placement devices (inclination and gamma ray, high temperature logging tools, measuring while drilling tools, logging while drilling tools, sand screens (to improve tolerance of ESP pumps), and equalizer technology for more efficient sweep of the formation by the injected steam, high temperature valves, and high temperature thermocouple systems.
While the foregoing is directed to embodiments of the invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This application is a continuation of U.S. application Ser. No. 13/768,872, filed Feb. 15, 2013, which is a continuation of U.S. application Ser. No. 12/836,992, filed Jul. 15, 2010, now U.S. Pat. No. 8,387,692, which claims benefit of U.S. Application Ser. No. 61/226,642, filed Jul. 17, 2009, and U.S. Application Ser. No. 61/226,650, filed Jul. 17, 2009, which are herein incorporated by reference in their entirety.
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