Methods and Systems for Upgrading Hydrocarbon

BACKGROUND

Recovery of heavy oil from subsurface deposits is often carried out at remote locations, such as on offshore platforms located many miles from land and oil sands deposits located in generally uninhabited areas where extreme weather conditions are common. As would be expected, many issues arise due to the remoteness of these locations. One example of such an issue is the difficulty in transporting the recovered viscous heavy oil to locations where upgrading equipment is available. Additionally, in the case of offshore platforms, there is a market penalty for oil that arrives back to shore in a highly viscous state.

As discussed in co-pending U.S. application Ser. No. 13/589,927, one possible solution to these problems is to subject the viscous heavy oil to upgrading at the remote location and prior to transporting the recovered material to refinery facilities located either onshore or in more populated areas. However, many materials needed to carry out upgrading processes can be scarce and/or expensive to produce at the remote locations where the heavy oil is initially recovered. For example, steam is used in several upgrading processes, but the standard boiler equipment typically available at remote locations and which can be used to generate steam have several shortcomings.

To begin with, steam generation by boilers can be very expensive. In some instances, almost 40% of the capital expenditure of upgrading equipment on an offshore platform can be attributed to boiler steam generation. The operating expenditure of boilers is also very high, due primarily to the need to pre-treat water used to create steam in a boiler. If the water supplied to the boiler for steam generation contains impurities (such as in the case of seawater), it must be pretreated in order to avoid scaling and sediment deposition on the inside of the boiler. Scaling build-up in the boiler decreases the boiler efficiency and can ultimately lead to equipment malfunction. Boilers also produce a flue gas that must be cleaned in order to ensure compliance with emissions standards. Additionally, roughly 10% of fuel heating value can be lost in the form of water vapor in the flue gas produced by boilers.

Process integration that can allow scarce resources to be reused is also difficult to accomplish with standard boiler equipment available at most remote facilities. For example, as noted above, only water free of certain impurities can be used in boilers to generate steam. However, most produced water streams are not free of such impurities, meaning that produced water can not be directly supplied to a boiler as part of a process integration scheme.

SUMMARY

The foregoing and other features, utilities and advantages of the invention will be apparent from the following more particular description of a preferred embodiment of the invention as illustrated in the accompanying drawings.

In some embodiments, a hydrocarbon upgrading system is disclosed. The system includes a combustor and a nozzle reactor. The combustor includes an oxidant inlet, a fuel inlet, a combustion chamber, and an atomizer nozzle in fluid communication with the combustion chamber. The nozzle reactor includes a reactor body having a reactor body passage with an injection end and an ejection end, a first material injector having a first material injection passage and being mounted in the nozzle reactor in material injecting communication with the injection end of the reactor body passage, and a second material feed port penetrating the reactor body. The first material injection passage has (a) an enlarged volume injection section, an enlarged volume ejection section, and a reduced volume mid-section intermediate the enlarged volume injection section and enlarged volume ejection section, (b) a material injection end in material injecting communication with the combustion chamber, and (c) a material ejection end in material injecting communication with the reactor body passage. The second material feed port is (a) adjacent to the material ejection end of the first material injection passage and (b) transverse to a first material injection passage axis extending from the material injection end to the material ejection end in the first material injection passage in the first material injector.

In some embodiments, a hydrocarbon recovery and upgrading system is disclosed. The system includes a combuster, a nozzle reactor, a steam assisted gravity drainage system, and a separation unit. The combustor includes an oxidant inlet, a fuel inlet, a combustion chamber, and an atomizer nozzle in fluid communication with the combustion chamber. The nozzle reactor includes a reactor body having a reactor body passage with an injection end and an ejection end, a first material injector having a first material injection passage and being mounted in the nozzle reactor in material injecting communication with the injection end of the reactor body passage, and a second material feed port penetrating the reactor body. The first material injection passage has (a) an enlarged volume injection section, an enlarged volume ejection section, and a reduced volume mid-section intermediate the enlarged volume injection section and enlarged volume ejection section, (b) a material injection end in material injecting communication with the combustion chamber, and (c) a material ejection end in material injecting communication with the reactor body passage. The second material feed port is (a) adjacent to the material ejection end of the first material injection passage and (b) transverse to a first material injection passage axis extending from the material injection end to the material ejection end in the first material injection passage in the first material injector. The steam assisted gravity drainage system includes a steam assisted gravity drainage injection well in material injecting communication with the combustion chamber and a steam assisted gravity drainage production well. The separation unit includes an inlet in fluid communication with the steam assisted gravity drainage production well, a fuel outlet in fluid communication with the fuel inlet and a hydrocarbon outlet in fluid communication with the second material feed port.

In some embodiments, a method of upgrading hydrocarbon material is disclosed. The method includes: injecting an oxidant stream and a fuel stream into a combustor and producing a combustion flame in a combustion chamber; injecting atomized pre-motive fluid into the combustion chamber and forming motive fluid; injecting the motive fluid into a nozzle reactor; and injecting a hydrocarbon material into the nozzle reactor.

In some embodiments, method of recovering and upgrading hydrocarbon is disclosed. The method includes: withdrawing a steam assisted gravity drainage product from a steam assisted gravity drainage production well; separating a fuel stream and a hydrocarbon stream from the steam assisted gravity drainage product; injecting an oxidant stream and the fuel stream into a combustor and producing a combustion flame in a combustion chamber; atomizing a pre-motive fluid stream, injecting the atomized pre-motive fluid into the combustion chamber, and forming motive fluid; injecting a first portion of the motive fluid into a nozzle reactor; injecting the hydrocarbon stream into the nozzle reactor; and injecting a second portion of the motive fluid into a steam assisted gravity drainage injection well.

BRIEF DESCRIPTION OF THE DRAWINGS

The preferred and other embodiments are disclosed in association with the accompanying drawings in which:

FIG. 1 is flow chart of embodiments of a hydrocarbon upgrading method described herein;

FIG. 2 is a cross-sectional view of a combustor suitable for use in embodiments described herein;

FIG. 3 is a cross-sectional view of a nozzle reactor suitable for use in embodiments described herein;

FIG. 4 is a cross-sectional view of a nozzle reactor suitable for use in embodiments described herein;

FIG. 5 is flow chart of embodiments of a hydrocarbon recovery and upgrading method described herein;

FIG. 6 is a block diagram illustrating embodiments of a hydrocarbon recovery and upgrading system described herein;

FIG. 7 shows a cross-sectional view of some embodiments of a nozzle reactor described herein;

FIG. 8 shows a cross-sectional view of the top portion of the nozzle reactor shown in FIG. 7;

FIG. 9 shows a cross-sectional perspective view of the mixing chamber in the nozzle reactor shown in FIG. 7; and

FIG. 10 shows a cross-sectional perspective view of the distributor from the nozzle reactor shown in FIG. 7.

DETAILED DESCRIPTION

With reference to FIG. 1, some embodiments of a method for upgrading hydrocarbon material include a step 1000 of injecting an oxidant stream and a fuel stream into a combustor and producing a combustion flame in a combustion chamber, a step 1100 of injecting atomized pre-motive fluid into the combustion chamber and forming motive fluid, a step 1200 of injecting the motive fluid into a nozzle reactor, and a step 1300 of injecting hydrocarbon material into the nozzle reactor. The method beneficially provides an alternative to boilers for motive fluid (e.g., steam) generation. In addition to being less cost-intensive than boilers, the method also allows for the use of untreated water in motive fluid generation, which further makes the method more cost effective than motive fluid generated by boilers. Other benefits of the method over the use of boilers for motive fluid generation include the elimination of a flue gas by-product and ability to take advantage of produced streams from other processes for better process integration.

In step 1000, an oxidant stream and a fuel stream are injected into a combustor. The reaction of the fuel stream and the oxidant stream creates a combustion flame in the combustion chamber of the combustor. An objective of step 1000 is to provide a heat from the reaction between the fuel stream and the oxidant stream to convert pre-motive fluid injected into the combustion chamber into motive fluid. The reaction between the oxidant stream and the fuel stream can also produce additional materials that can be used as motive fluids in upgrading processes such as cracking of hydrocarbon material in a nozzle reactor.

Any oxidant stream capable of being reacted with a fuel stream in a combustor to produce an exothermic reaction can be used in step 1000. In some embodiments, the oxidant stream is standard air from the surrounding environment. The oxidant stream will typically include a content of O₂and N₂. In some embodiments, the oxidant stream includes an O₂content in the range of from 18 to 21 vol %. Industrial oxygen can also be used alone or in combination with air as the oxidant stream. Industrial oxygen can include from 90 to 99 vol % oxygen. The use of industrial oxygen can advantageously reduce or eliminate nitrogen in the process and result in the production of a greater proportion of motive fluid. Additionally, when motive fluid produced using industrial oxygen is used in a nozzle reactor to produce cracked hydrocarbon products, the product leaving the nozzle reactor can be cleaner and more combustible. Other materials suitable for use as the oxidant stream include exhaust from a turbine (which can have depleted amounts of oxygen, such as less than 14 vol % O₂) and enriched air (which can include from 22 to 28 vol % O₂). Any combination of standard air, industrial oxygen, turbine exhaust, and enriched air can be used as the oxidant stream.

The oxidant stream injected into the combustor in step 1000 can be at a raised temperature and pressure to facilitate the reaction in the combustor. In some embodiments, the oxidant stream has a temperature in the range of from 1250 to 1500° F. and the oxidant stream can have a pressure of from 100 to 550 psig. When the source of the oxidant stream does not provide oxidant at the desired temperature and/or pressure, steps can be taken to adjust the temperature and/or pressure to within the desired ranges. Any suitable techniques for heating and/or pressurizing the oxidant stream can be used. For example, the oxidant stream can be run through a compressor to raise the pressure to within a suitable range.

In instances where a turbine, such as a gas turbine, is present at the remote location, the exhaust from the turbine can be used as the oxidant stream in step 1000. Use of the turbine exhaust as the oxidant stream can be useful because turbine exhaust typically has a raised temperature and pressure and has a desirable O₂content. Accordingly, use of turbine exhaust can eliminate or reduce the need to heat and pressurize the oxidant stream prior to injecting the oxidant stream into the combustor. In one example, turbine exhaust having an O₂of 14% is provided at a temperature of 1,400° F. and a pressure of 450 psig, meaning that the exhaust from the turbine can be directly injected into the combustor without the need for any pre-treatment. Such process integration lowers the overall cost of generating motive fluid.

The turbine integrated into the process can include the turbine used to generate power for the entire remote facility, such as the power needed for all rotating machines, powered electrical units, and accommodations (lights, air conditioning, etc.). Such turbines can be natural gas or fuel gas powered turbines. The motive fluid generation capacity can be calculated based on the exhaust gas temperature and flow rate from the turbine designed to power the remote facility, which in turn can be used to calculate the capacity of the nozzle reactor. An example of a commercially available gas turbine that can be used at the remote facility and integrated into the process is the Centaur 50 manufactured by Solar Turbines of California, USA. The Centaur 50 is a natural gas fired turbine that generates roughly 5 MW of electrical power.

In some embodiments, the exhaust from a custom engine can be used as the oxidant stream. The custom engine can include only an air compressor and a combustor section. The exhaust from such a custom engine can be used in the combustor to generate motive fluid in the same manner as described above when exhaust from a turbine is used in the combustor.

Any fuel stream capable of being reacted with an oxidant stream in a combustor to produce an exothermic reaction can be used in step 1000. Exemplary fuel streams include natural gas, methane, or any other low carbon-producing hydrocarbon. The fuel stream can also include hydrogen. The fuel stream does not require any pretreatment as long as the concentration of high molecular weight hydrocarbons is kept below 0.4 vol %.

The source of the fuel stream is generally not limited, and can include both fuel provided independently of any other processes being performed at the remote facility and fuel produced by other processes being performed at the remote facility. As described in greater detail below, in some embodiments the fuel stream is obtained in whole or in part from material recovered via a SAGD process being carried out at the remote location. Such material is typically subjected to various separation processes, one of which provides fuel suitable for use as a fuel stream in step 1000.

The oxidant stream and the fuel stream are injected into a combustor to react and provide an exothermic reaction. Any combustor suitable for reacting the oxidant stream and fuel stream to provide an exothermic reaction can be used. With reference to FIG. 2, a typical combustor 200 suitable for use in the methods described herein will include a fuel injector 210, an oxidant stream injector 220, an igniter 230, a combustion chamber 240 where the exothermic reaction takes place and where the combustion flame is produced, and a casing 250 housing all of the components of the combustor. The oxidant and fuel streams are injected into the combustor, where the two materials react, produce heat, and, with the aid of the igniter, provide a combustion flame. A basic example of the reaction that can take place inside the combustion zone when the fuel stream is methane is shown below:

CH₄+0.5O₂→CO+2H₂,h=−36 kJ/mol

In addition to CO and H₂, other reaction products that can be formed by the reaction of the fuel stream and the oxidant stream in the combustor include CO₂, N₂and H₂O.

The amount of the fuel stream and oxidant stream injected into the combustor can include any rates suitable for reacting the two streams and that can be handled by the combustor used. In some embodiments, the stoichiometric ratio of fuel to oxidant is greater than 1 (i.e., fuel rich). Typical combustion products for the reaction of standard air and natural gas (no additional steam added) at various stoichiometric ratios of fuel to air (Φ) are provided in Table 1.

TABLE 1

Φ = 1.1

Φ = 1.3

Φ = 1.5

Wet

Wet

Wet

(%)

(%)

(%)

N2
69
N2
66
N2
63

CO2
8
CO2
5.5
CO2
3.9

CO
2.5
CO
2.5
CO
9.0

H2
1.0
H2
4.0
H2
7.5

H2O
18.5
H2O
18.0
H2O
17.0

O2
0.0
O2
0.0
O2
0.0

Combustion of the fuel stream and standard air stream and sub-stoichiometric ratios lowers the adiabatic temperature of the combustion flame. Table 2 provides the adiabatic flame temperature at various Φ when the air stream is not pre-heated and when the air stream is pre-heated to 1,400° F.

TABLE 2

Without Air
With Air

Φ
Preheating (° F.)
Preheating (° F.)

1.0
3500
4100

1.3
3400
4000

1.5
2800
3400

2.0
2400
3000

Heat energy provided by the combustion flame is generally sufficient to produce motive fluid at a desired temperature and quench the products of combustion. For example, some cracking processes using nozzle reactors (discussed in greater detail below) operate more efficiently with motive fluid at 1,200° F. At many of the temperatures provided in Table 2 above, sufficient heat energy will be available to both produce motive fluid at 1,200° F. and quench the combustion products.

In step 1100, atomized pre-motive fluid is injected into the combustion chamber and motive fluid is formed. When the atomized pre-motive fluid enters the combustion chamber, the heat energy provided by the combustion reaction between the oxidant stream and the fuel stream converts the atomized pre-motive fluid into motive fluid. Thus produced, the motive fluid can be used for various recovery and upgrading processing being carried out at the remote facility.

The pre-motive fluid used in step 1100 can be selected from a variety of suitable materials. Generally speaking, the pre-motive fluid is a material that is suitable for use as a motive fluid in nozzle reactors Exemplary pre-motive fluids include, but are not limited to, water, natural gas, methanol, ethanol, ethane, propane, biodiesel, carbon monoxide, nitrogen, and combinations thereof.

When the pre-motive fluid injected into the combustion chamber is water, the water can be obtained from any suitable source available at the remote facility. The water may not require pretreatment, and therefore the source of the water is greatly expanded as compared to water sources that can be used when a boiler is used for steam generation. In some embodiments (e.g., where the remote location is an offshore platform), seawater can be used as the source of water. In some embodiments where seawater is used, some pretreatment may be carried out, such as filtration to remove solids or desalination.

In some embodiments, the water is obtained from material recovered by a SAGD process being carried out at the remote facility. Such material is typically subjected to various separation processes, one of which provides water suitable for use as the atomized pre-motive fluid in step 1100.

The pre-motive fluid injected into the combustion chamber is atomized. Atomized pre-motive fluid refers to small droplets of pre-motive fluid that are part of fine spray injected into the combustion chamber. Any technique capable of atomizing pre-motive fluid can be used. In some embodiments, atomization of the pre-motive fluid and injection of the atomized pre-motive fluid is performed by the same equipment.

In one example where the pre-motive fluid is water, high pressure atomizer nozzles can be used to both create an atomized water spray and inject the atomized water spray into the combustion chamber. Referring back to FIG. 2, the combustor 200 can be equipped with such a high pressure atomizer nozzle 260. The atomizer nozzle 260 is in fluid communication with the combustion chamber 240 such that the atomized water can be injected into the combustion chamber where heat energy is available to create steam from the atomized water droplets. As shown in FIG. 2, in some embodiments the atomizer nozzle 260 is located near the periphery of the combustion chamber 240. In this manner, the atomized water can enter the combustion chamber 240 around the entire circumference of the combustion flame.

In some embodiments, the amount of atomized pre-motive fluid injected into the combustion chamber is generally dependent on the amount of heat energy being produced inside the combustion chamber and available to convert the atomized pre-motive fluid to motive fluid. As noted above, some of the produced heat energy will be used to quench the other combustion products. In some embodiments, the atomized pre-motive fluid is injected into the combustion chamber to keep a pre-motive fluid to oil ratio in the range from 0.5 to 2.0.

Other reactions occur in the combustion chamber as a result of injecting the atomized pre-motive fluid into the combustion chamber and creating motive fluid. For example, when the pre-motive fluid is water, produced steam can react with unreacted fuel (e.g., methane) to produce H₂and CO, which is an endothermic reaction. An exemplary reaction between steam and methane fuel is provided below:

CH4+H2O→CO+3H2,h=+206 kJ/mol

Carbon monoxide produced from this reaction with react with steam to undergo an exothermic water gas shift reaction. For example:

CO+H2O→CO+H2,h=−41 kJ/mol

Taking into consideration all of these possible reactions, the final products that can be produced in the combustion chamber as a result of the introduction of the oxidant stream, the fuel stream, and atomized water into the combustion chamber include steam, H₂, CO, CO₂, and N₂. Each of these products can be used as motive fluids in the nozzle reactor cracking processes described in greater detail below.

In embodiments where the fuel stream includes hydrogen and the oxidant stream includes industrial oxygen, it is theorized that an efficiency higher than 98% can be obtained. This also would advantageously provide a zero carbon dioxide emission process.

Natural gas can also serve as a pre-motive fluid that can be converted into a motive fluid. Use of natural gas as a pre-motive fluid may require some modification to the processes described above. For example, use of natural gas as a pre-motive fluid may eliminate the need to atomize the pre-motive fluid prior to its introduction into a combustor. In some embodiments, natural gas is added to the combustor as a pre-motive fluid to heat and pressurize the pre-motive fluid and thereby put it in a condition for use as a motive fluid in a nozzle reactor. Accordingly, in some embodiments, natural gas is introduced into the combustor where it directly mixes with the fuel stream (and optionally the oxidant stream) to heat the natural gas. Atomized water can also be provided as a means of controlling the mixing and preventing unwanted reactions. For example, atomized water introduced into the combustion chamber where natural gas is mixing with the fuel stream can moderate the mixed fluid temperature and prevent the cracking of the natural gas into soot. The result of this modified process is the creation of heated and pressurized natural gas suitable for use as a motive fluid in a nozzle reactor. In some embodiments, the natural gas leaving the combustor has a temperature in the range of 1,200° F. and a pressure of 450 psig.

In some embodiments, the use of natural gas as a motive fluid can have a beneficial impact on upgrading performance in the nozzle reactor. For example, use of a motive fluid comprising 100% natural gas provide improved upgrading performance over motive fluid comprising mixture of natural gas and steam, or steam alone.

In alternative embodiments, natural gas is used as a pre-motive fluid to produce syngas for use as a motive fluid. This process can differ from the previously described use of natural gas as a pre-motive fluid in that reactions are allowed to take place within the combustor to thereby produce syngas. In some embodiments, natural gas is used as a pre-motive fluid in conjunction with using gas turbine exhaust as an oxidant. In such embodiments, reactions between gas turbine exhaust and the natural gas inside of the combustor creates hot syngas (CH₄, H₂, CO, H₂O, N₂, etc) suitable for use as a motive fluid. In carrying out this reaction, it can be important to ensure that all oxygen content from the gas turbine exhaust is consumed in the reforming reactions occurring inside the combustor.

In some embodiments, the direct fired combustor in a gas turbine can be used to create motive fluids. Gas turbines typically include direct fired combustors similar or identical to the direct fired combustor described above and shown in FIG. 2. The direct fired combustor in a gas turbine can be used to make motive fluid by utilizing the exhaust generated by the direct fired combustor in the gas turbine. In some embodiments, the exhaust generated can be directly mixed with atomized water to make steam that is suitable for use as a motive fluid. The exhaust (which can be O₂depleted as described above) can have a temperature in the range of 1,400° F. Exhaust at this temperature can be capable direct mixing with atomized water to produce steam. Any manner of mixing the exhaust with atomized water can be used, and the resulting steam can have a sufficient temperature and pressure to be used as a motive fluid (including when the steam created is superheated steam).

Another manner in which exhaust generated by a direct fired combustor in a gas turbine can be used to make motive fluid is through indirect heating of water. For example, the exhaust having a sufficiently high temperature (e.g., 1,400° F.) can be used in a shell and tube heat exchanger to transfer heat to water and thereby produce steam. The steam produced in this manner can be suitable for use as a motive fluid.

In steps 1200 and 1300, the motive fluid produced in the combustion chamber as part of step 1100 is injected into a nozzle reactor and a hydrocarbon material is injected into the nozzle reactor. An objective of injecting the two materials into the nozzle reactor is to crack the hydrocarbon material into lighter hydrocarbon compounds.

The nozzle reactor into which the motive fluid is injected can be any type of nozzle reactor capable of using motive fluid as a cracking material to upgrade hydrocarbon material. In some embodiments, the nozzle reactor into which the motive fluid is injected is the nozzle reactor described in U.S. Pat. No. 7,618,597, the entirety of which is hereby incorporated by reference. The nozzle reactor described in the '597 patent generally receives a motive fluid (also referred to as cracking material and, in this case, the motive fluid derived from the combustion chamber) and accelerates it to a supersonic speed via a converging and diverging injection passage. Hydrocarbon material is injected into the nozzle reactor adjacent the location the cracking material exits the injection passage and at a direction transverse to the direction of the cracking material. The interaction between the cracking material and the hydrocarbon material results in the cracking of the hydrocarbon material into a lighter hydrocarbon material.

With reference to FIG. 3, an exemplary nozzle reactor suitable for use in the methods and systems described herein is shown. The nozzle reactor, indicated generally at 10, has an injection end 12, a tubular reactor body 14 extending from the injection end 12, and an ejection port 13 in the reactor body 14 opposite its injection end 12. The injection end 12 includes an injection passage 15 extending into the interior reactor chamber 16 of the reactor body 14. The central axis A of the injection passage 15 is coaxial with the central axis B of the reactor chamber.

With continuing reference to FIG. 3, the injection passage 15 has a circular diametric cross-section and, as shown in the axially-extending cross-sectional view of FIG. 3, opposing inwardly curved side wall portions 17, 19 (i.e., curved inwardly toward the central axis A of the injection passage 15) extending along the axial length of the injection passage 15. In certain embodiments, the axially inwardly curved side wall portions 17, 19 of the injection passage 15 allow for a higher speed of injection when passing through the injection passage 15 into the reactor chamber 16.

In certain embodiments, the side wall of the injection passage 15 can provide one or more among: (i) uniform axial acceleration of material passing through the injection nozzle passage; (ii) minimal radial acceleration of such material; (iii) a smooth finish; (iv) absence of sharp edges; and (v) absence of sudden or sharp changes in direction. The side wall configuration can render the injection passage 15 substantially isentropic. These latter types of side wall and injection passage 15 features can be, among other things, particularly useful for pilot plant nozzle reactors of minimal size.

A material feed passage or channel 18 extends from the exterior of the junction of the injection end 12 and the tubular reactor body 14 toward the reaction chamber 16 transversely to the axis B of the interior reactor chamber 16. The material feed passage 18 penetrates an annular material feed port 20 adjacent the interior reactor chamber wall 22 at the end 24 of the interior reactor chamber 16 abutting the injection end 12. The material feed port 20 includes an annular, radially extending chamber feed slot 26 in material-injecting communication with the interior reactor chamber 16. The material feed port 20 is thus configured to inject feed material: (i) at about a 90° angle to the axis of travel of cracking material injected from the injection nozzle passage 15; (ii) around the entire circumference of a cracking material injected through the injection passage 15; and (iii) to impact the entire circumference of the free cracking material stream virtually immediately upon its emission from the injection passage 15 into the reactor chamber 16.

The annular material feed port 20 may have a U-shaped or C-shaped cross-section among others. In certain embodiments, the material feed port may be open to the interior reactor chamber 16, with no arms or barrier in the path of fluid flow from the material feed passage 18 toward the interior reactor chamber 16. The junction of the material feed port 20 and material feed passage 18 can have a radiused cross-section.

In alternative embodiments, the material feed passage 18, associated feed port 20, and/or injection passage 15 may have differing orientations and configurations, and there can be more than one material feed port and associated structure. Similarly, in certain embodiments the injection passage 15 may be located on or in the side 23 of the reactor chamber 16 (and if desired may include an annular cracking material port) rather than at the injection end 12 of the reactor chamber 16; and the material feed port 20 may be non-annular and located at the injection end 12 of the reactor chamber 16.

In the embodiment of FIG. 3, the interior reactor chamber 16 can be bounded by stepped, telescoping tubular side walls 28, 30, 32 extending along the axial length of the reactor body 14. In certain embodiments, the stepped side walls 28, 30, 32 are configured to: (i) allow a free jet of injected cracking material, such as superheated steam, natural gas, carbon dioxide, or other material, to travel generally along and within the conical jet path C generated by the ejection nozzle passage 15 along the axis 13 of the reactor chamber 16, while (ii) reducing the size or involvement of back flow areas, e.g., 34, 36, outside the conical or expanding jet path C, thereby forcing increased contact between the high speed cracking material stream within the conical path C and feed material, such as heavy hydrocarbons, injected through the feed port 20. As indicated by the drawing gaps 38, 40 in the embodiment of FIG. 3, the tubular reactor body 14 has an axial length (along axis B) that is much greater than its width. In the FIG. 3 embodiment, exemplary length-to-width ratios are typically in the range of 2 to 4 or more.

With reference now to FIG. 4 and the particular embodiment shown therein, the reactor body 44 includes a generally tubular central section 46 and a frustoconical ejection end 48 extending from the central section 46 opposite an insert end 50 of the central section 46, with the insert end 50 in turn abutting the injection nozzle 52. The insert end 50 of the central section 46 consists of a generally tubular central body 51. The central body 51 has a tubular material feed passage 54 extending from the external periphery 56 of the insert end 50 radially inwardly to injectingly communicate with the annular circumferential feed port depression or channel 58 in the otherwise planar, radially inwardly extending portion 59 of the axially stepped face 61 of the insert, end 50. The inwardly extending portion 59 abuts the planar radially internally extending portion 53 of a matingly stepped face 55 of the injection nozzle 52. The feed port channel 58 and axially opposed radially internally extending portion 53 of the injection nozzle 52 cooperatively provide an annular feed port 57 disposed transversely laterally, or radially outwardly, from the axis A of a preferably non-linear injection passage 60 in the injection nozzle 52.

The tubular body 51 of the insert end SD is secured within and adjacent the interior periphery 64 of the reactor body 44. The mechanism for securing the insert end 50 in this position may consist of an axially-extending nut-and-bolt arrangement (not shown) penetrating co-linearly mating passages (not shown) in: (i) an upper radially extending lip 66 on the reactor body 44; (ii) an abutting, radially outwardly extending thickened neck section 68 on the insert end 50; and (iii) in turn, the abutting injector nozzle 52. Other mechanisms for securing the insert end 50 within the reactor body 44 may include a press fit (not shown) or mating threads (not shown) on the outer periphery 62 of the tubular body 51 and on the inner periphery 64 of the reactor body 44. Seals, e.g., 70, may be mounted as desired between, for example, the radially extending lip 66 and the abutting the neck section 68 and the neck section 68 and the abutting injector nozzle 52.

The non-linear injection passage 60 has, from an axially-extending cross-sectional perspective, mating, radially inwardly curved opposing side wall sections 72, 74 extending along the axial length of the non-linear injection passage 60. The entry end 76 of injection passage 60 provides a rounded circumferential face abutting an injection feed tube 78, which can be bolted (not shown) to the mating planar, radially outwardly extending distal face 80 on the injection nozzle 52.

In the embodiment of FIG. 3, the nozzle passage 60 is a DeLaval type of nozzle and has an axially convergent section 82 abutting an intermediate relatively narrower throat section 84, which in turn abuts an axially divergent section 86. The nozzle passage 60 also has a circular diametric cross-section (i.e., in cross-sectional view perpendicular to the axis of the nozzle passage) all along its axial length. In certain embodiments, the nozzle passage 60 may also present a somewhat roundly curved thick 82, less curved thicker 84, and relatively even less curved and more gently sloped relatively thin 86 axially extending cross-sectional configuration from the entry end 76 to the injection end 88 of the injection passage 60 in the injection nozzle 52.

The nozzle passage 60 can thus be configured to present a substantially isentropic or frictionless configuration for the injection nozzle 52. This configuration may vary, however, depending on the application involved in order to yield a substantially isentropic configuration for the application.

The injection passage 60 is formed in a replaceable injection nozzle insert 90 press-fit or threaded into a mating injection nozzle mounting passage 92 extending axially through an injection nozzle body 94 of the injection nozzle 52. The injection nozzle insert 90 is preferably made of hardened steel alloy, and the balance of the nozzle reactor 100 components other than seals, if any, are preferably made of steel or stainless steel.

In the particular embodiment shown in FIG. 3, the narrowest diameter D within the injection passage is 140 mm. The diameter E of the ejection passage opening 96 in the ejection end 48 of the reactor body 44 is 2.2 meters. The axial length of the reactor body 44, from the injection end 88 of the injector passage 60 to the ejection passage opening 96, is 10 meters.

The interior peripheries 89, 91 of the insert end 50 and the tubular central section 46, respectively, cooperatively provide a stepped or telescoped structure expanding radially outwardly from the injection end 88 of the injection or injector passage 60 toward the frustoconical end 48 of the reactor body 44. The particular dimensions of the various components, however, will vary based on the particular application for the nozzle reactor, generally 100. Factors taken into account in determining the particular dimensions include the physical properties of the cracking gas (density, enthalpy, entropy, heat capacity, etc.) and the pressure ratio from the entry end 76 to the injection end 88 of the injector passage 60.

In certain embodiments having one or more non-linear cracking gas injection passages, e.g., 60, such as the convergent/divergent configuration of FIG. 3, the pressure differential can yield a steady increase in the kinetic energy of the cracking material as it moves along the axial length of the cracking gas injection passage(s) 60. The cracking material may thereby eject from the ejection end 88 of the injection passage 60 into the interior of the reactor body 44 at supersonic speed with a commensurately relatively high level of kinetic energy. In these embodiments, the level of kinetic energy of the supersonic discharge cracking material is therefore greater than can be achieved by certain prior art straight-through.

Feed stock is injected into the material feed passage 54 and then through the mating annular feed port 57. The feed stock thereby travels radially inwardly to impact a transversely (i.e., axially) traveling high speed cracking mateiral (for example, steam, natural gas, carbon dioxide or other gas not shown) virtually immediately upon its ejection from the ejection end 88 of the injection passage 60. The collision of the radially injected feed stock with the axially traveling high speed steam jet delivers kinetic and thermal energy to the feed stock. The applicants believe that this process may continue, but with diminished intensity and productivity, through the length of the reactor body 44 as injected feed stock is forced along the axis of the reactor body 44 and yet constrained from avoiding contact with the jet stream by the telescoping interior walls, e.g., 89, 91101, of the reactor body 44. Depending on the nature of the feed stock and its pre-feed treatment, differing results can be procured, such as cracking of heavy hydrocarbons, including bitumen, into lighter hydrocarbons.

FIGS. 7 and 8 show cross-sectional views of another embodiment of a nozzle reactor 100 suitable for use in the methods described herein. The nozzle reactor 100 includes a head portion 102 coupled to a body portion 104. A main passage 106 extends through both the head portion 102 and the body portion 104. The head and body portions 102, 104 are coupled together so that the central axes of the main passage 106 in each portion 102, 104 are coaxial so that the main passage 106 extends straight through the nozzle reactor 100.

It should be noted that for purposes of this disclosure, the term “coupled” means the joining of two members directly or indirectly to one another. Such joining may be stationary in nature or movable in nature. Such joining may be achieved with the two members or the two members and any additional intermediate members being integrally formed as a single unitary body with one another or with the two members or the two members and any additional intermediate member being attached to one another. Such joining may be permanent in nature or alternatively may be removable or releasable in nature.

The nozzle reactor 100 includes a feed passage 108 that is in fluid communication with the main passage 106. The feed passage 108 intersects the main passage 106 at a location between the portions 102, 104. The main passage 106 includes an entry opening 110 at the top of the head portion 102 and an exit opening 112 at the bottom of the body portion 104. The feed passage 108 also includes an entry opening 114 on the side of the body portion 104 and an exit opening 116 that is located where the feed passage 108 meets the main passage 106.

During operation, the nozzle reactor 100 includes a reacting fluid that flows through the main passage 106. The reacting fluid enters through the entry opening 110, travels the length of the main passage 106, and exits the nozzle reactor 100 out of the exit opening 112. A feed material flows through the feed passage 108. The feed material enters through the entry opening 114, travels through the feed passage 106, and exits into the main passage 108 at exit opening 116.

The main passage 106 is shaped to accelerate the reacting fluid. The main passage 106 may have any suitable geometry that is capable of doing this. As shown in FIGS. 7 and 8, the main passage 106 includes a first region having a convergent section 120 (also referred to herein as a contraction section), a throat 122, and a divergent section 124 (also referred to herein as an expansion section). The first region is in the head portion 102 of the nozzle reactor 100.

The convergent section 120 is where the main passage 106 narrows from a wide diameter to a smaller diameter, and the divergent section 124 is where the main passage 106 expands from a smaller diameter to a larger diameter. The throat 122 is the narrowest point of the main passage 106 between the convergent section 120 and the divergent section 124. When viewed from the side, the main passage 106 appears to be pinched in the middle, making a carefully balanced, asymmetric hourglass-like shape. This configuration is commonly referred to as a convergent-divergent nozzle or “con-di nozzle”.

The convergent section of the main passage 106 accelerates subsonic fluids since the mass flow rate is constant and the material must accelerate to pass through the smaller opening. The flow will reach sonic velocity or Mach 1 at the throat 122 provided that the pressure ratio is high enough. In this situation, the main passage 106 is said to be in a choked flow condition.

Increasing the pressure ratio further does not increase the Mach number at the throat 122 beyond unity. However, the flow downstream from the throat 122 is free to expand and can reach supersonic velocities. It should be noted that Mach 1 can be a very high speed for a hot fluid since the speed of sound varies as the square root of absolute temperature. Thus the speed reached at the throat 122 can be far higher than the speed of sound at sea level.

The divergent section 124 of the main passage 106 slows subsonic fluids, but accelerates sonic or supersonic fluids. A convergent-divergent geometry can therefore accelerate fluids in a choked flow condition to supersonic speeds. The convergent-divergent geometry can be used to accelerate the hot, pressurized reacting fluid to supersonic speeds, and upon expansion, to shape the exhaust flow so that the heat energy propelling the flow is maximally converted into kinetic energy.

The flow rate of the reacting fluid through the convergent-divergent nozzle is isentropic (fluid entropy is nearly constant). At subsonic flow the fluid is compressible so that sound, a small pressure wave, can propagate through it. At the throat 122, where the cross sectional area is a minimum, the fluid velocity locally becomes sonic (Mach number=1.0). As the cross sectional area increases the gas begins to expand and the gas flow increases to supersonic velocities where a sound wave cannot propagate backwards through the fluid as viewed in the frame of reference of the nozzle (Mach number>1.0).

The main passage 106 only reaches a choked flow condition at the throat 122 if the pressure and mass flow rate is sufficient to reach sonic speeds, otherwise supersonic flow is not achieved and the main passage will act as a venturi tube. In order to achieve supersonic flow, the entry pressure to the nozzle reactor 100 should be significantly above ambient pressure.

The pressure of the fluid at the exit of the divergent section 124 of the main passage 106 can be low, but should not be too low. The exit pressure can be significantly below ambient pressure since pressure cannot travel upstream through the supersonic flow. However, if the pressure is too far below ambient, then the flow will cease to be supersonic or the flow will separate within the divergent section 124 of the main passage 106 forming an unstable jet that “flops” around and damages the main passage 106. In one embodiment, the ambient pressure is no higher than approximately 2-3 times the pressure in the supersonic gas at the exit.

The supersonic reacting fluid collides and mixes with the feed material in the nozzle reactor 100 to produce the desired reaction. The high speeds involved and the resulting collision produces a significant amount of kinetic energy that helps facilitate the desired reaction. The reacting fluid and/or the feed material may also be pre-heated to provide additional thermal energy to react the materials.

The nozzle reactor 100 may be configured to accelerate the reacting fluid to at least approximately Mach 1, at least approximately Mach 1.5, or, desirably, at least approximately Mach 2. The nozzle reactor may also be configured to accelerate the reacting fluid to approximately Mach 1 to approximately Mach 7, approximately Mach 1.5 to approximately Mach 6, or, desirably, approximately Mach 2 to approximately Mach 5.

As shown in FIG. 8, the main passage 106 has a circular cross-section and opposing converging side walls 126, 128. The side walls 126, 128 curve inwardly toward the central axis of the main passage 106. The side walls 126, 128 form the convergent section 120 of the main passage 106 and accelerate the reacting fluid as described above.

The main passage 106 also includes opposing diverging side walls 130, 132. The side walls 130, 132 curve outwardly (when viewed in the direction of flow) away from the central axis of the main passage 106. The side walls 130, 132 form the divergent section 124 of the main passage 106 that allows the sonic fluid to expand and reach supersonic velocities.

The side walls 126, 128, 130, 132 of the main passage 106 provide uniform axial acceleration of the reacting fluid with minimal radial acceleration. The side walls 126, 128, 130, 132 may also have a smooth surface or finish with an absence of sharp edges that may disrupt the flow. The configuration of the side walls 126, 128, 130, 132 renders the main passage 106 substantially isentropic.

The feed passage 108 extends from the exterior of the body portion 104 to an annular chamber 134 formed by head and body portions 102, 104. The portions 102, 104 each have an opposing cavity so that when they are coupled together the cavities combine to form the annular chamber 134. A seal 136 is positioned along the outer circumference of the annular chamber 134 to prevent the feed material from leaking through the space between the head and body portions 102, 104.

It should be appreciated that the head and body portions 102, 104 may be coupled together in any suitable manner. Regardless of the method or devices used, the head and body portions 102, 104 should be coupled together in a way that prevents the feed material from leaking and withstands the forces generated in the interior. In one embodiment, the portions 102, 104 are coupled together using bolts that extend through holes in the outer flanges of the portions 102, 104.

The nozzle reactor 100 includes a distributor 140 positioned between the head and body portions 102, 104. The distributor 140 prevents the feed material from flowing directly from the opening 141 of the feed passage 108 to the main passage 106. Instead, the distributor 140 annularly and uniformly distributes the feed material into contact with the reacting fluid flowing in the main passage 106.

As shown in FIG. 10, the distributor 140 includes an outer circular wall 148 that extends between the head and body portions 102, 104 and forms the inner boundary of the annular chamber 134. A seal or gasket may be provided at the interface between the distributor 140 and the head and body portions 102, 104 to prevent feed material from leaking around the edges.

The distributor 140 includes a plurality of holes 144 that extend through the outer wall 148 and into an interior chamber 146. The holes 144 are evenly spaced around the outside of the distributor 140 to provide even flow into the interior chamber 146. The interior chamber 146 is where the main passage 106 and the feed passage 108 meet and the feed material comes into contact with the supersonic reacting fluid.

The distributor 140 is thus configured to inject the feed material at about a 90° angle to the axis of travel of the reacting fluid in the main passage 106 around the entire circumference of the reacting fluid. The feed material thus forms an annulus of flow that extends toward the main passage 106. The number and size of the holes 144 are selected to provide a pressure drop across the distributor 140 that ensures that the flow through each hole 144 is approximately the same. In one embodiment, the pressure drop across the distributor is at least approximately 2000 pascals, at least approximately 3000 pascals, or at least approximately 5000 pascals.

Referring to FIG. 9, holes 144 are shown having a circular cross-section. Circular holes 144 are suitable for effective nozzle reactor operation when the nozzle reactor is relatively small and handling production capacities less than, e.g., 1,000 bbl/day. At such production capacities, the feed material passing through the circular holes will break up into the smaller droplet size necessary for efficient mixing or shearing with the reacting fluid.

The distributor 140 includes a wear ring 150 positioned immediately adjacent to and downstream of the location where the feed passage 108 meets the main passage 106. The collision of the reacting fluid and the feed material causes a lot of wear in this area. The wear ring is a physically separate component that is capable of being periodically removed and replaced.

As shown in FIG. 10, the distributor 140 includes an annular recess 152 that is sized to receive and support the wear ring 150. The wear ring 150 is coupled to the distributor 140 to prevent it from moving during operation. The wear ring 150 may be coupled to the distributor in any suitable manner. For example, the wear ring 150 may be welded or bolted to the distributor 140. If the wear ring 150 is welded to the distributor 140, as shown in FIG. 9, the wear ring 150 can be removed by grinding the weld off. In some embodiments, the weld or bolt need not protrude upward into the interior chamber 146 to a significant degree.

The wear ring 150 can be removed by separating the head portion 102 from the body portion 104. With the head portion 102 removed, the distributor 140 and/or the wear ring 150 are readily accessible. The user can remove and/or replace the wear ring 150 or the entire distributor 140, if necessary.

As shown in FIGS. 7 and 8, the main passage 106 expands after passing through the wear ring 150. This can be referred to as expansion area 160 (also referred to herein as an expansion chamber). The expansion area 160 is formed largely by the distributor 140, but can also be formed by the body portion 104.

Following the expansion area 160, the main passage 106 includes a second region having a converging-diverging shape. The second region is in the body portion 104 of the nozzle reactor 100. In this region, the main passage includes a convergent section 170 (also referred to herein as a contraction section), a throat 172, and a divergent section 174 (also referred to herein as an expansion section). The converging-diverging shape of the second region differs from that of the first region in that it is much larger. In one embodiment, the throat 172 is at least 2-5 times as large as the throat 122.

The second region provides additional mixing and residence time to react the reacting fluid and the feed material. The main passage 106 is configured to allow a portion of the reaction mixture to flow backward from the exit opening 112 along the outer wall 176 to the expansion area 160. The backflow then mixes with the stream of material exiting the distributor 140. This mixing action also helps drive the reaction to completion.

The combustion chamber of the combustor can be in fluid communication with the cracking material injection passage of the nozzle reactor such that the produced motive fluid passes directly into the nozzle reactor. The motive fluid exiting the combustion chamber and entering the nozzle reactor is passed through the cracking material injection passage where, as described above, the motive fluid is accelerated to a supersonic speed. Any amount of motive fluid necessary to crack hydrocarbon material injected into the nozzle reactor can be supplied into the nozzle reactor.

In some embodiments, supplemental motive fluid can be provided to the nozzle reactor, such as in the case where the combustor does not produce sufficient motive fluid for cracking the amount of hydrocarbon injected into the nozzle reactor. The supplemental motive fluid can be joined with the motive fluid produced by the combustor prior to injection into the nozzle reactor. Any suitable source of supplemental motive fluid can be used. In embodiments where the motive fluid is steam, traditional steam generation boilers can be used to produce supplemental motive fluid. In offshore contexts, steam generation boilers are a good source of supplemental motive fluid because the offshore platform already uses steam generation boilers for other processes carried out on the offshore platform.

In step 1300, the hydrocarbon material to be upgraded is injected into the nozzle reactor. When a nozzle reactor as described above is used, the hydrocarbon material is injected into the nozzle reactor at a location adjacent to where the motive fluid exits the cracking material injection passage and a direction transverse to the direction the motive fluid enters the reactor body passage.

Any hydrocarbon material capable of being upgraded in the nozzle reactor through interaction with motive fluid travelling at supersonic speeds can be used in step 1300. In some embodiments, the hydrocarbon material is a heavy hydrocarbon material, such as a hydrocarbon material having a molecular weight greater than 500. Such hydrocarbon materials can include bitumen and asphaltenes. In some embodiments, the hydrocarbon material is hydrocarbon material that is recovered from SAGD recovery processes being carried out at the same remote facility as the nozzle reactor upgrading. Such material when recovered via a SAGD process is typically subjected to one or more separation units, and one potential output stream of the separation units may be a heavy hydrocarbon stream.

In some embodiments, some deposits may appear within the nozzle reactor as a result of the upgrading process. Such scale build up should be monitored. In some embodiments, treatment of the water prior to injection into the nozzle reactor can be provided in order to reduce or avoid scale build up. Such treatments can include distillation, desalting, and/or desalination depending on the source.

Some embodiments of the method can include further process integration such that the upgrading processes are assisted by the recovery processes and vice versa. With reference to FIG. 5, some embodiments of a method for recovering and upgrading hydrocarbon material include a step 500 of withdrawing a steam assisted gravity drainage product from a steam assisted gravity drainage production well, a step 510 of separating a fuel stream and a hydrocarbon stream from the steam assisted gravity drainage product, a step 520 of injecting a combustion stream and the fuel stream into a combustor and producing a combustion flame in a combustion chamber, a step 530 of atomizing a water stream, injecting the atomized water into the combustion chamber, and forming steam, a step 540 of injecting a first portion of the steam into a nozzle reactor, a step 550 of injecting they hydrocarbon stream into the nozzle reactor, and a step 560 of injecting a second portion of the steam into a steam assisted gravity drainage injection well. In such a method, the SAGD recovery processing assists the upgrading processing by providing the fuel and hydrocarbon streams, and the upgrading processing assists the SAGD recovery processing by providing a portion of the necessary steam.

In step 500, a SAGD production well is provided through which SAGD product can be withdrawn. The SAGD production well can be any type of SAGD production well known to those of ordinary skill in the art and is part of any type of SAGD system to known to those of ordinary skill in the art. Generally speaking, the SAGD production well has a first end that is located within a deposit of hydrocarbon material. Typically, this end of the production well will be oriented in a horizontal direction and will be located under a SAGD injection well that introduces steam into the deposit of hydrocarbon material. The steam introduced into the deposit of hydrocarbon material will lower the viscosity of the hydrocarbon material until it flows downwardly under the influence of gravity to the SAGD production well located under the SAGD injection well. The SAGD production well receives this hydrocarbon material and provides a channel for the material to be pumped upwardly to the opposite end of the production well. The opposite end of the production well is located above ground.

The SAGD product brought to the surface by the SAGD production well can have a variety of components. In some embodiments, the SAGD product includes hydrocarbon material, fuel, and water, as well as other components. The hydrocarbon material component of the SAGD product can be from 15 to 35% of the product and can include, e.g., bitumen, asphaltenes and other heavy hydrocarbon material. The fuel component of the SAGD product can be from 0 to 0.5% of the product and can include, e.g., natural gas and methane. The water component of the SAGD product can be from 65 to 85% of the product.

The withdrawn SAGD product is subjected to separation processing in step 520. An objective of the separation processing is to separate a fuel stream and a hydrocarbon stream from the SAGD product. Once a fuel stream and a hydrocarbon stream are separated from the SAGD product, the streams can be used in steam generation and hydrocarbon upgrading to provide for beneficial process integration. Any equipment capable of separating these streams from the SAGD product can be used. In some embodiments, the separations are carried out in multiple separation apparatus. For example, a first separation can be carried out in an emulsion breaker tank, followed by a separation in a distillation unit.

The fuel stream separated in step 510 can be used in step 520, where an air stream and the fuel stream are injected into a combustor and a combustion flame is produced in the combustion chamber. Step 520 is similar or identical to step 100 described in greater detail above, with the condition that at least a portion of the fuel stream used in step 520 is derived from the SAGD product withdrawn in step 500 and separated in step 510. Typically, make-up fuel, such as imported natural gas, will be necessary to provide a sufficient amount of fuel to produce steam.

The water needed for 530 is typically provided by a source of water independent from the SAGD product. Any water source suitable for use in generating steam in a combustor can be used. The water is atomized, injected into the combustion chamber, and steam is formed. Step 530 is similar or identical to step 110 described in greater detail above. In some embodiments, water from the SAGD product can be used in addition to or in place of the independent water source, although water from the SAGD produce will typically require pretreatment prior to being used in the combustor to generate steam. A typical required pretreatment process for water derived from SAGD product is a silica removing process. Without such a silica removing process, scaling of process equipment such as the nozzle reactor can occur.

When the upgrading process is integrated with the SAGD recovery process, the steam produced in step 530 can be used in both processes. In step 540, a first portion of the steam is injected into a nozzle reactor to carry out hydrocarbon cracking and upgrading as described in greater detail above. Step 540 is similar or identical to step 120 described in greater detail above, with the condition that only portion of the steam produced in the combustion chamber is injected into the nozzle reactor. The first portion of steam injected into the nozzle reactor can be any suitable amount needed to carry out the upgrading in the nozzle reactor. Any mechanism known to those of ordinary skill in the art can be used withdraw only a portion of the steam produced in the combustion chamber.

In step 550, the hydrocarbon stream separated from the SAGD product in step 510 is injected into the nozzle reactor to interact with the steam injected into the nozzle reactor in step 540 and crack and upgrade the hydrocarbon material. Step 550 can be similar or identical to step 130 described in greater detail above, with the condition that at least a portion of the hydrocarbon material used in step 550 is derived from the SAGD product withdrawn in step 500 and separated in step 510. To the extent necessary, additional make-up hydrocarbon material may be used.

In step 560, a second portion of the steam formed in the combustion chamber in step 530 is injected into a SAGD injection well. An objective of injecting steam into the SAGD injection well is to assist with continued hydrocarbon recovery via the SAGD operation. The SAGD injection well can be any type of SAGD production well known to those of ordinary skill in the art for recovery hydrocarbon material from hydrocarbon deposits. Generally speaking, the SAGD injection well has a first end located within a deposit of hydrocarbon material and a second end above ground where steam is entered into the well. Typically, the end of the injection well within the deposit will be oriented in a horizontal direction and will be located above a SAGD production. Steam transported through the SAGD injection well is injected into the deposit of hydrocarbon material in order to lower the viscosity of the hydrocarbon material and cause it to flow downwardly under the force of gravity. Located beneath the SAGD injection well is the SAGD production well discussed above, which can receive the flowing hydrocarbon material and transport it above ground.

In some embodiments, the amount of steam required for the SAGD recovery operation is supplied by the second portion of steam generated in the combustion chamber and allocated for use in the SAGD process. However, in embodiments where an insufficient amount of steam is formed in the combustion chamber, make-sup steam can be provided to the SAGD injection well. Any suitable source of make-up steam can be used.

With reference to FIG. 6, a system that can be used to carry out embodiments of the methods described above includes a combustor 610, a SAGD injector 620, a nozzle reactor 630, a SAGD producer 640, and a separation unit 650. As described in greater detail above, fuel 611, water 612, and air 613 are injected into the combustor 610 to produce steam 615. A portion of the produced steam 615a can be transported to the SAGD injector 620 for use in carrying out the SAGD process. A portion of the produced steam 615b can be transported to the nozzle reactor 630 for use in upgrading a stream of heavy hydrocarbon material 631 being injected into the nozzle reactor 630. The SAGD producer 640 produces a SAGD product 641 that can include hydrocarbon material, fuel, and water. The SAGD product 641 is therefore sent to a separation unit 650 capable of separating a fuel stream 652 and a hydrocarbon stream 653 from the SAGD product 641. Leftover SAGD product, including water, can leave the separation unit 650 via leftover stream 651. Fuel stream 652 separated from the SAGD product 641 in the separation unit 650 can be sent to the combustor 610, while hydrocarbon stream 653 in need of upgrading can be sent to the nozzle reactor 630.

As described in greater detail above, the combustor 610 can be any type of combustor suitable for converting water into steam, and in some embodiments, includes an atomizer for receiving water 612 and injecting the water 612 in atomized form into the combustion chamber of the combustor 610. The source of the water is not limited, and can include, for example, sea water when the system is located on an off-shore platform. The air 613 injected into the combustor can come from any suitable source, and in some embodiments if provided by a turbine. Gas turbine exhaust can be useful in the process described herein because it is provided at a high temperature and pressure. If the air 613 is not gas turbine exhaust, additional equipment to heat and compress the air prior to injection into the combustor 610 can be provided. Gas turbine exhaust can also be used in conjunction with an air make-up stream where the gas turbine does not provide a sufficient amount of air for the combustor 610. The fuel 611 provided to the combustor can be any fuel for operating the combustor. In some embodiments, the fuel 611 is natural gas. As described in greater detail below, a portion or all of the fuel 611 and the water 612 can be provided by a SAGD process integrated with combustor 610. To the extent that the SAGD process does not provide a sufficient amount of water and/or fuel, make-up streams can be provided.

The steam 615 generated by the combustor can be divided into two streams, with one steam stream 615b being directed to a nozzle reactor 630 and the other steam stream 615a being directed to a SAGD injector 620. Any manner of separating the steam 615 into the two streams 615a, 615b can be provided and the amount of steam 615 diverted to each stream can be determined based on the amount of steam 615 produced by the combustor 610 and the steam demands of the SAGD injector 620 and the nozzle reactor 630.

The steam 615a directed to the SAGD injector 620 is injected into the ground to soften hydrocarbon material such as bitumen and cause the bitumen to flow down towards a SAGD producer. The SAGD injector 620 can include a plurality of SAGD injectors 620 such that the steam 615a is distributed to each of the SAGD injectors 620 and a larger area of the bituminous deposit is subjected to steam injection. In instances where the steam 615a is not sufficient to supply one or more of the SAGD injectors 620, make up steam can be provided.

Steam 615b transported to the nozzle reactor 630 is injected into the nozzle reactor 630 to interact with a hydrocarbon stream 631 also injected into the nozzle reactor 630. The two materials interact to crack and upgrade the hydrocarbon stream 631. In some embodiments, the nozzle reactor 630 is the nozzle reactor described above and illustrated in FIGS. 3 and 4 such that the steam 615b is injected into the nozzle reactor 630 in a direction perpendicular to the direction the hydrocarbon stream 631 is injected into the nozzle reactor. In instances where steam 615b does not provide a sufficient amount of steam for the nozzle reactor 630, a make-up steam stream can be provided to supplement steam 615b. The products leaving the nozzle reactor 630 can be re-used in the process, such as when the product stream includes fuel gas, water, and/or non-upgraded (or insufficiently upgraded) hydrocarbon. The fuel gas and water can be separated from the product stream and re-used in the combustor 610, while the non-upgraded hydrocarbon can be re-injected into the nozzle reactor 630.

As noted above, the SAGD injector 620 provides steam into a bituminous deposit to cause bitumen to flow down to a SAGD producer 640. The SAGD producer 640, which may actually be a plurality of SAGD producers, collects the softened bitumen and transports it above ground. The SAGD product 641 transported above ground by the SAGD producer can include heavy hydrocarbon material (such as bitumen), water, and fuel gas (such as natural gas), along with other components. Accordingly, a portion of the SAGD product 641 can be transported to a separation unit 650, where the components of the SAGD product 641 are separated to be used in the system.

Any separation unit 650 capable of separating a fuel stream 652 and a hydrocarbon stream 653 from the SAGD product 641 can be used, including various settling and distillation apparatus. Once separated, the fuel stream 652 can be sent to the combustor 610 for use in steam generation. The hydrocarbon stream 653 can be sent to the nozzle reactor 630 for upgrading. Fuel stream make-up and/or hydrocarbon stream make-up can each be provided in instances where the separation unit 650 does not provide suitable amounts of either one of these components.

While the above described systems and methods generally reference use of a single nozzle reactor, multiple nozzle reactors can be used in the systems and methods described herein. The multiple nozzle reactors can be arranged in series, in parallel, or any combination of the two. Use of multiple nozzle reactors in series can generally help to increase the conversion of heavy hydrocarbon material into lighter hydrocarbon material, such as by separating heavy hydrocarbon exiting a first nozzle reactor and running it through a second nozzle reactor located downstream and whose operating conditions are adjusted to improve the conversion of heavy hydrocarbons. The use of multiple nozzle reactors in parallel can increase the amount of hydrocarbon material that can be processed and can mitigate issues relating to scaling up nozzle reactors to handle larger capacities.

In some embodiments of the systems and methods described herein, separation processing is carried out on the products produced by the nozzle reactor. Such separation processing can be carried out on an offshore platform in embodiments where the nozzle reactor and/or combustor are located on an offshore platform. Any manner of separating the hydrocarbon product can be used. In some embodiments, cyclone separators are used. Cyclone separators can be useful due to their relatively small foot print. The hydrocarbon products can be separated into, for example, a lights, middle distillate, and residue stream. The residue stream may be recycled back into the nozzle reactor for further upgrading.

While the invention has been particularly shown and described with reference to a preferred embodiment thereof, it will be understood by those skilled in the art that various other changes in the form and details may be made without departing from the spirit and scope of the invention.

A presently preferred embodiment of the present invention and many of its improvements have been described with a degree of particularity. It should be understood that this description has been made by way of example, and that the invention is defined by the scope of the following claims.

Methods and Systems for Upgrading Hydrocarbon

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