Patent Application
20080083537
So that the manner in which the features and advantages of the present invention, which will become apparent, are attained and can be understood in more detail, more particular description of the invention briefly summarized above may be had by reference to the embodiments thereof that are illustrated in the appended drawings which form a part of this specification. It is to be noted, however, that the drawings illustrate only some embodiments of the invention and therefore are not to be considered limiting of its scope as the invention may admit to other equally effective embodiments.
Although the following detailed description contains many specific details for purposes of illustration, anyone of ordinary skill in the art will appreciate that many variations and alterations to the following details are within the scope of the invention. Accordingly, the exemplary embodiments of the invention described below are set forth without any loss of generality to, and without imposing limitations thereon, the present invention.
A separate CO2 line also may be utilized. The CO2 may be injected at various and/or multiple locations along the liner, including at the head end, through the liner 15 or injector 13, or at the exit prior to the packer 23, depending on the application. In the one embodiment, burner 11 is enclosed within an outer shell or burner casing 22.
The burner 11 may be suspended by fuel line 19, oxidizer line 21 and steam line 20 while being lowered down the well. In another embodiment, a shroud or string of tubing (neither shown) may suspend burner 11 by attaching to injector 13 and/or cooling liner 15. When installed, burner 11 could be supported on packer 23 or casing 17. In one embodiment, burner casing 22 and burner 11 form an annular steam channel 25, which substantially surrounds the exterior surfaces of injector 13 and cooling liner 15.
In operation, steam having a preferable steam quality of approximately 50% to 90% (e.g., 80% to 100%), or some degree of superheated steam, may be formed at the surface of a well and fluidly communicated to steam channel 25 at a pressure of, for example, about 1600 psi. The steam arriving in steam channel 25 may have a steam quality of approximately 70% to 90% due to heat loss during transportation down the well. In one embodiment, burner 11 has a power output of approximately 13 MMBtu/hr and is designed to produce about 3200 bpd (barrels per day) of superheated steam (cold water equivalent) with an outlet temperature of around 700° F. at full load. Steam at lower temperatures may also be feasible.
Steam communicated to burner 11 through steam channel 25 may enter burner 11 through a plurality of holes in cooling liner 15. Combustion occurring within cooling liner 15 heats the steam and increases its steam quality. The heated, high-quality steam and combustion products exit burner 11 through outlet 24. The steam and combustion products (i.e., the combusted fuel and oxidizer (e.g., products) or exhaust gases) then may enter an oil-bearing formation in order to, for example, upgrade and improve the mobility of heavy crude oils held in the formation. Those skilled in the art will recognize that burners having the design of burner 11 may be built to have almost any power output, and to provide almost any steam output and steam quality.
The invention is suitable for many different types and sizes of wells. For example, in one embodiment designed for use in a well having a well casing diameter of 7⅝-inches, burner casing 22 has an outer diameter of 6 inches and a wall thickness of 0.125 inches; cooling liner wall 27 has an outer diameter of 5 inches, an inner diameter of 4.75 inches, and a wall thickness of 0.125 inches; injector face plate 29 has a diameter of 4.65 inches; steam channel 25 has an annular width between cooling liner wall 27 and burner casing 22 of 0.375 inches; and gap 35 has a width of 0.050 inches.
In one embodiment, fuel holes 93, 97 and oxidizer holes 91, 95, 99, 101 produce a shower head stream pattern of fuel and oxidizer rather than an impinging stream pattern or a fogging effect. Although other designs may be used and are within the scope of the present invention, a shower head design moves the streams of fuel and oxidizer farther away from injector face plate 29. This provides a longer stand-off distance between the high flame temperature of the combusting fuel and injector face plate 29, which in turn helps to keep injector face plate 29 cooler.
Effusion cooling section 63 may be characterized by the inclusion of a plurality of effusion holes 71. Effusion cooling section 63 acts to inject small jets of steam along the surface of cooling liner 15, thus providing a layer of cooler gases to protect liner 15. In one embodiment, effusion holes 71 may be angled 20 degrees off of an internal surface of cooling liner 15 and aimed downstream of inlet 67, as shown in
Effusion cooling and jet mixing section 65 may be characterized by the inclusion of a plurality of effusion holes 71 as well as a plurality of mixing holes 73. Mixing holes 73 are larger than effusion holes 71, as shown in
In another embodiment, the invention further comprises injecting liquid water into the downhole burner and cooling the injector and/or liner with the water. The water may be introduced to the well and injected in numerous ways such as those described herein.
Table 1 summarizes the qualities and placement of the holes of sections 63, 65 in one embodiment. The first column defines the section of cooling liner 15 and the second column describes the type of hole. The third and fourth columns describe the starting and ending position of the occurrence of the holes in relation to the top of section 63, which may correspond to the bottom surface of injector 13 (see
Embodiments of the downhole burner may be operated using various fuels. In one embodiment, the burner may be fueled by hydrogen, methane, natural gas, or syngas. One type of syngas composition comprises 44.65 mole % CO, 47.56 mole % H2, 6.80 mole % CO2, 0.37 mole % CH4, 0.12 mole % Ar, 0.29 mole % N2, and 0.21 mole % H2S+COS. One embodiment of the oxidizer for all the fuels includes oxygen and could be, for example, air, rich air, or pure oxygen. Although other temperatures may be employed, an inlet temperature for the fuel is about 240° F. and an inlet temperature for the oxidant is about 186.5° F.
Table 2 summarizes the operating parameters of one embodiment of a downhole burner that is similar to that described in
Embodiments of the downhole burner also may be operated using CO2 as a coolant in addition to steam. CO2 may be injected through the injector or through the cooling liner. The power required to heat the steam increases when diluents such as CO2 are added. In the example of Table 3, a quantity of CO2 sufficient to result in 20 volumetric percent of CO2 in the exhaust stream of the burner is added downstream of the injector. It can be seen that the increase in inlet pressures is minimal although the required power has increased.
In the example of Table 4, a quantity of CO2 sufficient to result in 20 volumetric percent of CO2 in the exhaust stream of the burner has been added through the fuel line and fuel holes of the burner. It can be seen that the fuel inlet pressure is much higher than in the example of Table 3. CO2 also could be delivered through the oxidizer line and oxidizer holes, or a combination of delivery methods could be used. For example, the CO2 could be delivered into burner 11 with the fuel.
In other embodiments, the diameters of the fuel and oxidizer injectors 31 may differ to optimize the injector plate for a particular set of conditions. In the present embodiment, the diameters are adequate for the given conditions, assuming that supply pressure on the surface is increased when necessary.
Burner 11 can be useful in numerous operations in several environments. For example, burner 11 can be used for the recovery of heavy oil, tar sands, shale oil, bitumen, and methane hydrates. Such operations with burner 11 are envisioned in situ under tundra, in land-based wells, and under sea.
The invention has numerous advantages. The dual purpose cooling/mixing liner maintains low wall temperatures and stresses, and mixes coolants with the combustion effluent. The head end section of the liner is used for transpiration cooling of the line through the use of effusion holes angled downstream of the injector plate. This allows for coolant (primarily partially saturated steam at about 70% to 80% steam quality) to be injected along the walls, which maintains low temperatures and stress levels along liner walls, and maintains flow along the walls and out of the combustion zone to prevent flame extinguishment.
The back end section of the liner provides jet mixing of steam (and other coolants) for the combustion effluent. The pressure difference across the liner provides sufficient jet penetration through larger mixing holes to mix coolants into the main burner flow, and superheat the coolant steam. The staggered hole pattern with varying sizes and multiple axial distances promotes good mixing of the coolant and combustion effluent prior to exhaust into the formation. A secondary use of transpiration cooling of the liner is accomplished through use of effusion holes angled downstream of the combustion zone to maintain low temperatures and stress level along liner walls in jet mixing section of the burner similar to transpiration cooling used in the head end section.
The invention further provides coolant flexibility such that the liner can be used in current or modified embodiment with various vapor/gaseous phase coolants, including but not limited to oil production enhancing coolants, in addition to the primary coolant, steam. The liner maintains effectiveness as both a cooling and mixing component when additional coolants are used.
The showerhead injector uses alternating rings of axial fuel and oxidizer jets to provide a uniform stable diffusion flame zone at multiple pressures and turndown flow rates. It is designed to keep the flame zone away from injector face to prevent overheating of the injector plate. The injector has flexibility to be used with multiple fuels and oxidizers, such as hydrogen, natural gases of various compositions, and syngases of various compositions, as well as mixtures of these primary fuels. The oxidizers include oxygen (e.g., 90-95% purity) as well as air and “oxygen-rich” air for appropriate applications. The oil production enhancing coolants (e.g., carbon dioxide) can be mixed with the fuel and injected through the injector plate.
In other embodiments, the invention is used to disperse nanocatalysts into heavy oil and/or bitumen-bearing formations under conditions of time, temperature, and pressure that cause refining reactions to occur, such as those described herein. The nanocatalysts are injected into the burner via any of the conduits or means described herein (including an optional separate line), and a nanocatalyst-reducing gas mixture is passed through the burner where it is heated, or, the mixture is injected alongside the downhole steam generator. In either case, the mixture is then injected into the formation where it promotes converting and upgrading the hydrocarbon downhole, in situ, including sulfur reduction. The reducing gas may comprise hydrogen, syngas, or hydrogen donors such as tetralin or decalin. The appropriate catalyst causes the reactions to take place at a temperature that is lower than the temperature of thermal (i.e., non-catalytic) reactions. Advantageously, less coke is formed at the lower temperature.
Alternatively, the carrier gas is preheated on the surface prior to entering the transfer vessel. The carrier gas may be preheated using any heat source and heat exchange device. The preheated gas is supplied to the transfer vessel at an elevated temperature that provides for heat losses in the heat transfer vessel as well as the well bore and still be sufficient to maintain the in situ catalytic reactions for which the catalyst was designed.
The nanocatalyst-reducing gas mixture is injected into the formation where it promotes converting and upgrading the hydrocarbon. When the in situ catalytic reaction comprises hydrovisbreaking, hydrocracling, hydrodesulfurization, or other hydrotreating reactions, hydrogen is the preferred carrier gas. For other types of reactions, the carrier gas is one or more of the reactants. For example, if the reaction that is promoted is in situ combustion, the carrier gas is oxygen, rich air, or air. In another embodiment, carbon dioxide is the carrier gas for a cracking catalyst that promotes in situ cracking of the hydrocarbon in the formation.
Referring now to
When the cycle of catalyst preparation in one vessel and the catalyst transfer from the other vessel is complete, the roles of the two vessels are reversed. The vessel where the catalyst was prepared becomes the transfer vessel, and the vessel that had the catalyst transferred out becomes the catalyst preparation vessel. This alternation of roles continues until the catalyst injection into the formation is no longer required.
One embodiment of the invention employs nanocatalysts prepared in a conventional manner. See, e.g., Enhancing Activity of Iron-based Catalyst Supported on Carbon Nanoparticles by Adding Nickel and Molybdenum, Ungula Priyanto, Kinya Sakanishi, Osamu Okuma, and Isao Mochida, Preprints of Symposia: 220th ACS National Meeting, August 20-24, 2000, Washington, D.C. The catalyst is transported into a petroleum-bearing formation by a carrier gas. The gas is a reducing gas such as hydrogen and the catalyst is designed to promote an in situ reaction between the reducing gas and the oil in the reservoir.
In order for the conversion and upgrading reactions to occur in the reservoir, the catalyst, reducing gas, and the heavy oil or bitumen must be in intimate contact at a temperature of at least 400° F., and at a hydrogen partial pressure of at least 100 psi. The intimate contact, the desired temperature, and the desired pressure are brought about by means of a downhole steam generator. See, e.g., U.S. Pat. No. 4,465,130. The steam, nanocatalysts, and unburned reducing gases are forced into the formation by the pressure created by the downhole steam generator. Because the reducing gas is the carrier for the nanocatalysts, these two components will tend to travel together in the petroleum-bearing formation. Under the requisite heat and pressure, the reducing gas catalytically reacts with the heavy oil and bitumen thereby reducing its viscosity and % sulfur as well as increasing its API gravity.
Some catalysts comprise a metal adsorbed on a carbon nanotube. For those catalysts, the temperature of the upgrading reactions must be below the temperature that allows the steam to react with the carbon tubes. Other catalysts, such as TiO2 or TiO2-based, are not affected by steam and are effective in catalyzing upgrading reactions.
In the embodiment of
This embodiment has many advantages including that the downhole steam generator makes it possible to bring together hydrogen, a hydrogenation catalyst, heavy oil in place, heat, and pressure, thereby causing catalytic reactions to occur in the reservoir. Because catalysts with a wide variety of reactivities and selectivities can be synthesized, the invention permits many opportunities for in situ upgrading. The nature of catalysts is to promote reactions at milder conditions (e.g., lower temperatures and pressures) than thermal or non-catalytic reactions. This means that hydrogenation, for example, may be conducted in situ at shallower depths than conventional pyrolysis and other thermal reactions.
Another advantage of the process when used without a downhole steam generator is the ease of operation without the generator. The lack of downhole equipment results in less maintenance and less downtime for injection of the catalyst and reactants. One disadvantage is the heat losses in the catalyst preparation/transfer vessels and in the well bore. The invention provides a platform technology that is applicable to a wide range of in situ reactions in a wide range of heavy oil, ultraheavy oil, natural bitumen, and lighter deposits.
Furthermore, the invention has many applications, including in situ catalytic hydrogenation, in situ catalytic hydrovisbreaking, in situ catalytic hydrocracking, in situ catalytic combustion, in situ catalytic reforming, in situ catalytic alkylation, in situ catalytic isomerization, and other in situ catalytic refining reactions. Although all of these reactions are used in conventional petroleum refining, none of them are used for in situ catalytic reactions.
Although some embodiments of the present invention have been described in detail, it should be understood that various changes, substitutions, and alterations can be made hereupon without departing from the principle and scope of the invention.
This non-provisional patent application claims priority to and the benefit of U.S. Provisional Patent App. Nos. 60/850,181, filed Oct. 9, 2006; 60/867,073, filed Nov. 6, 2006; and 60/850,181, filed Jan. 18, 2007.
| Number | Date | Country | |
|---|---|---|---|
| 60850181 | Oct 2006 | US | |
| 60857073 | Nov 2006 | US | |
| 60885442 | US |
