US20120073810A1

US20120073810A1 - Situ hydrocarbon upgrading with fluid generated to provide steam and hydrogen

Info

Publication number: US20120073810A1
Application number: US13/239,018
Authority: US
Inventors: Scott Macadam; James P. Seaba; Wayne Reid Dreher, JR.; Joe D. Allison
Original assignee: ConocoPhillips Co
Current assignee: ConocoPhillips Co
Priority date: 2010-09-24
Filing date: 2011-09-21
Publication date: 2012-03-29
Also published as: CA2812589A1; WO2012040358A1

Abstract

Methods and apparatus relate to recovery of in situ upgraded hydrocarbons by injecting steam and hydrogen into a reservoir containing the hydrocarbons. A mixture output generated as water is vaporized by direct contact with flow from fuel-rich combustion provides the steam and hydrogen. The steam heats the hydrocarbons facilitating flow of the hydrocarbons and reaction of the hydrogen with the hydrocarbons to enable hydroprocessing prior to recovery of the hydrocarbons to surface.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims the benefit of and priority to U.S. Provisional Application Ser. No. 61/386,361 filed Sep. 24, 2010, entitled “In Situ Hydrocarbon Upgrading with Fluid Generated to Provide Steam and Hydrogen,” which is hereby incorporated by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

None

FIELD OF THE INVENTION

Embodiments of the invention relate to methods and systems for delivering hydrogen and steam to a subsurface reservoir for upgrading of hydrocarbons in situ.

BACKGROUND OF THE INVENTION

In order to recover oil from certain geologic formations, injection of steam increases mobility of the oil within the formation via an exemplary process known as steam assisted gravity drainage (SAGD). Produced fluids include the oil and condensate from the steam. Surface handling of the produced fluids separates the oil from water that may be recycled to generate additional steam for sustaining the process.
Viscosity reduction obtained during production by heating the oil with the steam is based on temperature of the oil and therefore temporary. Subsequent transport of the oil through a pipeline, for example, thus relies on diluting the oil with less viscous hydrocarbons. However, blending the oil creates problems due to added costs, potential to cause fouling and optimization issues at refineries utilizing such blends as feedstock.
In situ upgrading of the oil offers permanent viscosity reduction to facilitate transportation thereof and improves refinery demand for the oil. Extent of the in situ upgrading in past approaches depends on various factors including presence of a hydrogen donor within the formation for reacting with the oil to yield products that are upgraded. However, cost of generating hydrogen at a surface facility, difficulty in transporting hydrogen or expense of compounds that function as the hydrogen donor make prior techniques to supply the hydrogen donor where wanted in the formation undesirable.
Therefore, a need exists for methods and systems of recovering subsurface upgraded oil from a reservoir.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment, a method of in situ upgrading hydrocarbons includes generating a hydrogen and steam containing injection stream by vaporization of water contacted with flow from combustion of a gaseous hydrocarbon fuel with an oxidant and at an oxygen:fuel equivalence ratio less than 1. The method further includes introducing the injection stream into a formation to contact, heat and hydroprocess hydrocarbons in the formation. In addition, the method includes recovering to surface the hydrocarbons that have been upgraded.
According to one embodiment, a system for in situ upgrading hydrocarbons includes a hydrogen and steam generator having an output of an injection stream produced by vaporization of water contacted with flow from combustion of a gaseous hydrocarbon fuel with an oxidant and at an oxygen:fuel equivalence ratio less than 1. An injector conveys the injection stream into a formation to contact, heat and hydroprocess hydrocarbons in the formation. A recovery assembly produces to surface the hydrocarbons that are upgraded.
For one embodiment, a method of in situ upgrading hydrocarbons includes injecting hydrogen and steam into a first wellbore of a steam assisted gravity drainage well pair. Operation of a direct steam generator under fuel-rich conditions generates the steam and hydrogen. The method also includes recovering upgraded hydrocarbons to surface through a second wellbore of the steam assisted gravity drainage well pair.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefits thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings.

FIG. 1 is a schematic of a production system in which cogeneration of steam and hydrogen enables steam assisted recovery of in situ upgraded hydrocarbons, according to one embodiment of the invention.

FIG. 2 is a schematic of a production system illustrating cogeneration of steam and hydrogen combined with a wellbore heater and optional catalyst for use in steam assisted recovery of in situ upgraded hydrocarbons, according to one embodiment of the invention.

FIG. 3 is a graph of modeled results for hydrogen and carbon monoxide levels in product gas from a direct steam generator versus oxygen to fuel equivalence ratio for combustion in the direct steam generator, according to one embodiment of the invention.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.
Embodiments of the invention relate to recovery of in situ upgraded hydrocarbons by injecting steam and hydrogen into a reservoir containing the hydrocarbons. A mixture output generated as water is vaporized by direct contact with flow from fuel-rich combustion provides the steam and hydrogen. The steam heats the hydrocarbons facilitating flow of the hydrocarbons and reaction of the hydrogen with the hydrocarbons to enable hydroprocessing prior to recovery of the hydrocarbons to surface.
FIG. 1 illustrates a production system with a fuel-rich direct steam generator 100 coupled to supply a fluid stream to an injection well 101. The fluid stream includes steam and hydrogen (H₂) produced by the generator 100. In operation, heat transfer from the steam makes petroleum products mobile enough to enable or facilitate both upgrading by reaction of the petroleum products with the hydrogen and recovery of the petroleum products with, for example, a production well 102.
In some embodiments, the injection and production wells 101, 102 traverse through an earth formation 103 containing the petroleum products, such as heavy oil or bitumen, heated by the fluid stream. For some embodiments, the injection well 101 includes a horizontal borehole portion that is disposed above (e.g., 0 to 6 meters above) and parallel to a horizontal borehole portion of the production well 102. While shown in an exemplary steam assisted gravity drainage (SAGD) well pair orientation, some embodiments utilize other configurations of the injection well 101 and the production well 102, which may be combined with the injection well 101 or arranged crosswise relative to the injection well 101, for example. Further, upgrading processes described herein may rely on other production techniques, such as use of the fluid stream from the generator 100 as a drive fluid or cyclic injecting and producing during alternating periods of time.
The generator 100 includes a fuel input 104, an oxidant input 106 and a water input 108 that are coupled to respective sources of fuel, oxidant and water and are all in fluid communication with a flow path through the generator 100. The generator 100 differs from indirect-fired boilers since transfer of heat produced from combustion occurs by direct contact of the water with combustion gasses. This direct contact avoids thermal inefficiency due to heat transfer resistance across boiler tubes. Tubing 112 conveys the fluid stream from the generator 100 to the injection well 101 by coupling an output from the flow path through the generator 100 with the injection well 101.
Examples of the oxidant include air, oxygen enriched air and oxygen (i.e., oxy combustion with greater than 95% pure O₂or greater than 99% pure O₂), which may be separated from air. Sources for the fuel include natural gas or other hydrocarbon gas mixtures that may contain at least 90% methane. As explained further herein, at least some of the hydrogen in the fluid stream comes from operation of the generator 100 with the fuel introduced in excess of a supply rate that achieves complete combustion given amount of oxygen supplied to the generator 100.
Such fuel-rich operating conditions of the generator 100 thus provide combustion at an oxygen:fuel equivalence ratio less than 1. The oxidant:fuel equivalence ratio as used herein refers to a ratio of actual oxidant:fuel ratio to a stoichiometric oxidant:fuel ratio. A stoichiometric mixture contains just enough of the oxygen for complete burning of the fuel such that all the oxygen is consumed in reaction without the oxygen passing through in combustion products.
The generator 100 produces the hydrogen at a pressure and temperature suitable for reservoir injection conditions. Producing the hydrogen mixed with the steam within the fluid stream from the generator 100 therefore avoids alternative surface storage of hydrogen or separate hydrogen production and injection equipment. This cogeneration of the hydrogen and the steam together within the generator 100 also enables injection of the hydrogen while limiting safety issues associated with handling of the hydrogen. Compared to in situ combustion for generation of the hydrogen, the hydrogen being part of the fluid stream from the generator 100 further enables delivery of the hydrogen through the conduit 112 and the injection well 101 to locations where desired in the formation 103.
During operation, the steam upon exiting the injection well 101 and passing into the formation 103 condenses and contacts the petroleum products to create a mixture of condensate from the steam and the petroleum products. The mixture migrates through the formation 103 due to gravity drainage and is gathered at the production well 102 through which the mixture is recovered to surface. A separation process may divide the mixture into components for recycling of recovered water back to the generator 100.
Mobility provided by heat transfer from the steam to the petroleum products makes the petroleum products available to mix with the hydrogen to achieve the hydroprocessing. Depending on factors such as temperature, exemplary reactions for the hydroprocessing include desulfurization, olefin and aromatic saturation and hydrocracking With respect to the saturation of olefins, unsaturated bonds accept the hydrogen becoming capped to prevent undesired polymerization of the petroleum products. At least a few of the reactions may proceed to some extent even below an injection temperature that the fluid stream produced by the generator 100 enters the formation 103.
FIG. 2 shows a device 200 for cogeneration of steam and hydrogen, an injector 201 and a recovery assembly including a producer 202 all configured to function as described with respect to FIG. 1. In addition, a wellbore heater 250 and optional catalyst 252 facilitate in situ upgrading of hydrocarbons by hydroprocessing reactions. Disposing the heater 250 and the catalyst 252 along the producer 202 places the catalyst 252 in a flow path of the hydrocarbons from the formation 103 to the surface. The heater 250 also thereby increases temperature of the hydrocarbons in contact with the catalyst 252 to a reaction temperature sufficient to achieve the hydroprocessing reactions.
The hydrogen required for the reactions comes from the hydrogen that is introduced through the injector 201. Proximity of the producer 202 and the injector 201 allows for mixing of the hydrogen with surrounding fluids at hydroprocessing zones where the temperature is increased by the heater 250 to promote the reactions. Flow of production fluids including the hydrocarbons and water further mix with the hydrogen and help in transporting the hydrogen toward the hydroprocessing zones.
In some embodiments, the heater 250 achieves subsurface heating of the hydrocarbons to the reaction temperature above 300° C. or above 400° C. The heater 250 supplements the heating of the hydrocarbons achieved by the fluid stream that is produced by the generator 200 since the reaction temperature may be above an injection temperature that the fluid stream enters the formation 103. For some embodiments, the heater 250 provides a non-steam based source of heat using various other techniques for heating of the hydrocarbons.
Examples of the heater 250 include an induction heating tool, a radio frequency or microwave heating device or a resistive heating element. The heater 250 utilizing an exemplary induction heating method includes a coiled conductive metal through which current is passed to create heat by inducing hysteresis losses in a metal liner of the producer 202. In this example of the heater 250, current also passes into the reservoir surrounding the producer 202 for additional heating of the hydroprocessing zones.
Several approaches enable disposing of the catalyst 252 subsurface for the in situ upgrading. For example, passing the catalyst 252 through the producer 202 to where desired may be done as part of a water-in-oil emulsion or to create a packed bed. In some embodiments, solid particles forming the catalyst 252 provide packing in an annulus of the producer 202.
For some embodiments, the catalyst 252 defines a hydroprocessing catalyst. Selection of the catalyst 252 depends on poisoning susceptibility by sulfur species, water oxidation and nitrogen in order to account for conditions that lead to transition metal catalyst poisoning. Suitable compounds for the catalyst 252 include metal sulfides (e.g., MoS₂, WS₂, CoMoS and NiMoS), metal carbides (MoC and WC) or other refractory type metal compounds such as metal phosphides and metal borides.
In some embodiments, a water-gas shift reaction produces additional hydrogen to supplement hydrogen production within generators described herein. The water-gas shift reaction yields carbon dioxide and the hydrogen by conversion of water vapor and carbon monoxide also output in fluid streams from the generators. In some embodiments, the water-gas shift reaction occurs once the carbon monoxide is injected into a hydrocarbon reservoir.
The catalyst 252 as shown in FIG. 2 may thus define a water-gas shift catalyst in a flow path of the carbon monoxide mixed with the steam. In some embodiments, composition of the catalyst 252 promotes both the hydroprocessing and water-gas shift reactions or may include compounds that are mixed together or disposed in separate locations and define the hydroprocessing catalyst that is different from the water-gas shift catalyst. Exemplary catalysts 252 specific for the water-gas shift reaction include copper/zinc/aluminum (Cr/Zn/Al) and iron/chromium/copper (Fe/Cr/Cu).
The upgrading of the hydrocarbons yields products with permanent viscosity reduction. This viscosity reduction helps to at least limit amount of diluting required for transport of the products. In addition, the upgrading facilitates further processing of the products at refineries.
FIG. 3 illustrates a plot of modeled results for hydrogen and carbon monoxide levels in product gas from a direct steam generator versus oxygen to fuel equivalence ratio for combustion in the direct steam generator. First line 301 with triangular data points represents the hydrogen levels. The generator produces over 19 volume percent hydrogen on a dry basis at an oxygen:fuel equivalence ratio of 0.9. By contrast, conventional operation with an oxygen:fuel equivalence ratio greater than 1 yields less than 1 volume percent hydrogen on a dry basis. While the oxygen:fuel equivalence ratio of 0.9 is a minimum depicted, the generator may operate at lower values of the oxygen:fuel equivalence ratio and hence may produce even higher concentrations of the hydrogen than indicated by the plot.
However, the steam produced per unit of the fuel burned decreases as the oxygen:fuel equivalence ratio drops. For example, the oxygen:fuel equivalence ratio of 0.9 provides about 86-88% of the steam per unit of the fuel burned relative to operating at stochiometric conditions (i.e., the oxygen:fuel equivalence ratio equals 1). Selection of the oxygen:fuel equivalence ratio thus depends on an economic balance between steam production rate and hydrogen production rate.
Second line 302 with square data points represents the carbon monoxide levels. The carbon monoxide level increases with the hydrogen level as the oxygen:fuel equivalence ratio decreases. Therefore, increase in the carbon monoxide available for the water-gas shift reaction to make additional hydrogen occurs in a synergistic relation with raising of the hydrogen output based on the oxygen:fuel equivalence ratio. The generator produces over 12 volume percent carbon monoxide on a dry basis at the oxygen:fuel equivalence ratio of 0.9. In contrast, conventional operation with the oxygen:fuel equivalence ratio greater than 1 yields less than 1 volume percent carbon monoxide on a dry basis.
For some embodiments, fluid streams produced by generators described herein contains at least 5 volume percent hydrogen on a dry basis, at least 10 volume percent hydrogen on a dry basis or at least 15 volume percent hydrogen on a dry basis. Operation with the oxygen:fuel equivalence ratio less than 0.98, less than 0.95, less than 0.92 or less than 0.9 may provide desired amounts of the hydrogen within the fluid streams. While limited by reduction in the steam production, ability to approach full hydrocarbon upgrading relies on utilizing concentrations of the hydrogen as high as possible.
In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as additional embodiments of the present invention.
Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.

Claims

1. A method, comprising:

generating a hydrogen and steam containing injection stream by vaporization of water contacted with flow from combustion of a gaseous hydrocarbon fuel with an oxidant and at an oxygen:fuel equivalence ratio less than 1;

introducing the injection stream into a formation to contact, heat and hydroprocess hydrocarbons in the formation;

recovering to surface the hydrocarbons that have been upgraded.

2. The method according to claim 1, wherein the oxygen:fuel equivalence ratio is less than 0.95.

3. The method according to claim 1, wherein the injection stream contains at least 5 volume percent hydrogen on a dry basis.

4. The method according to claim 1, wherein the injection stream contains at least 15 volume percent hydrogen on a dry basis.

5. The method according to claim 1, further comprising disposing a hydroprocessing catalyst in a flow path of the hydrocarbons from the formation to the surface.

6. The method according to claim 1, further comprising disposing a water-gas shift catalyst in a flow path of the injection stream.

7. The method according to claim 1, further comprising subsurface heating of the hydrocarbons with a non-steam based heat source.

8. The method according to claim 1, wherein the introducing and the recovering are through a steam assisted gravity drainage well pair.

9. The method according to claim 1, further comprising disposing a hydroprocessing catalyst along a producer wellbore through which the hydrocarbons are recovered and heating the hydrocarbons in contact with the catalyst to a reaction temperature above an injection temperature that the injection stream enters the formation.

10. The method according to claim 1, further comprising disposing a water-gas shift catalyst in a flow path of the injection stream and disposing a hydroprocessing catalyst that is different from the water-gas shift catalyst in a flow path of the hydrocarbons from the formation to the surface.

11. The method according to claim 1, further comprising subsurface heating of the hydrocarbons to above 300° C.

12. The method according to claim 1, further comprising subsurface heating of the hydrocarbons to above 400° C.

13. The method according to claim 1, wherein the hydrogen facilitates hydroprocessing reactions that include desulfurization, olefin and aromatic saturation and hydrocracking

14. A system, comprising:

a hydrogen and steam generator having an output of an injection stream produced by vaporization of water contacted with flow from combustion of a gaseous hydrocarbon fuel with an oxidant and at an oxygen:fuel equivalence ratio less than 1;

an injector configured to convey the injection stream into a formation to contact, heat and hydroprocess hydrocarbons in the formation, and

a recovery assembly that produces to surface the hydrocarbons that are upgraded.

15. The system according to claim 14, further comprising a hydroprocessing catalyst disposed in a flow path of the hydrocarbons from the formation to the surface.

16. The system according to claim 14, further comprising a non-steam based heat source for subsurface heating of the hydrocarbons.

17. A method, comprising:

injecting hydrogen and steam into a first wellbore of a steam assisted gravity drainage well pair, wherein the steam and hydrogen are generated by operation of a direct steam generator under fuel-rich conditions; and

recovering upgraded hydrocarbons to surface through a second wellbore of the steam assisted gravity drainage well pair.

18. The method according to claim 17, wherein the first wellbore extends horizontal spaced from the second wellbore that extends horizontal deeper in the formation than the first wellbore.

19. The method according to claim 17, further comprising heating the hydrocarbons to a reaction temperature above an injection temperature that the injection stream enters the formation.

20. The method according to claim 17, further comprising disposing a hydroprocessing catalyst in a flow path of the hydrocarbons from the formation to the surface.