Abstract:
Apparatus and methods recover hydrocarbonaceous and additional products from oil/tar sands. The method includes the steps of forming a hole in a body of oil or tar sand, positioning an apertured sleeve within the hole to minimize fill-in of the sand, positioning a gas inlet conduit into the apertured sleeve, and introducing a heated, pressurized processing gas into the sleeve through the gas inlet conduit, such that the heated, pressurized processing gas penetrates into the sand through the apertures, thereby converting bitumen within the sand into hydrocarbonaceous products. The processing gas and hydrocarbonaceous products are withdrawn as effluent gas through the hole under relative negative pressure. A mesh screen may be supported between the apertured sleeve and the body of oil or tar sand.

Description:
FIELD OF THE INVENTION 
     The present invention relates generally to the recovery of hydrocarbonaceous products from oil/tar sands and, in particular, to a process and system for recovering such products and byproducts with significantly reduced environmental impact. 
     BACKGROUND OF THE INVENTION 
     The terms oil/tar sands, often referred to as ‘extra heavy oil,’ are types of bitumen deposits. The deposits are naturally occurring mixtures of sand or clay, water and an extremely dense and viscous form of petroleum called bitumen. They are found in large amounts in many countries throughout the world, but are found in extremely large quantities in Canada and Venezuela. 
     Due to the fact that extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the sands are often extracted by strip mining or the oil made to flow into wells by in situ techniques which reduce the viscosity by injecting steam, solvents, and/or hot air into the sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production. 
     Like all mining and non-renewable resource development projects, oil sands operations have an effect on the environment. Oil sands projects may affect the land when the bitumen is initially mined and with large deposits of toxic chemicals, the water during the separation process and through the drainage of rivers, and the air due to the release of carbon dioxide and other emissions, as well as deforestation. Clearly any improvements in the techniques use to extract hydrocarbonaceous products from shale and sands would be appreciated, particularly if efficiency is improved and/or environmental impact is reduced. 
     Certain improvements with respect to the recovery of products from oil shales are disclosed in U.S. Pat. No. 7,041,051. Unlike other prior art processes, the in situ body of oil sands to be treated is not surface mined. Rather, the process includes drilling a hole in the body of oil sands, and locating a processing gas inlet conduit within the hole such that the bottom end of the processing inlet gas conduit is near the bottom of the hole. An effluent gas conduit is anchored around the opening of the hole at the ground surface of the body of oil sand. A processing gas is introduced into an above-ground combustor. In the combustor, the processing gas, which contains enough oxygen to support combustion, is heated by burning a combustible material introduced into the combustor in the presence of the processing gas. The resultant heated processing gas is of a temperature sufficient to convert kerogen in the oil shale to gaseous hydrocarbonaceous products. 
     The heat from the heated processing gas, as well as radiant heat from the processing gas inlet conduit, create a nonburning thermal energy front in the oil sands surrounding the hole. The bitumen is thus pyrolyzed and converted into hydrocarbonaceous products. The products produced during pyrolysis of the bitumen are in gaseous form and are withdrawn with the processing gas as an effluent gas through the hole and into the effluent gas conduit. The effluent gas is transferred through the effluent gas conduit into a condenser where the effluent gas is allowed to expand and cool so as to condense a portion of the hydrocarbonaceous products into liquid fractions. In the condenser, a remaining gaseous fraction of hydrocarbonaceous products is separated from the liquid fraction of hydrocarbonaceous products. The gaseous fraction is preferably filtered and or scrubbed so as to separate the upgraded gas products from any waste gases including the inorganic gas carbon dioxide. 
     A portion of the upgraded hydrocarbon gas may be recycled to the combustor to provide combustible material for fueling combustion within the combustor, and while a portion of the waste inorganic gas may be recycled to the compressor for augmenting the supply of carbon dioxide in the processing gas, further improvements are possible, both in the generation of the heated, processing gas as well as the recovery of products and byproducts produced in the condenser. 
     SUMMARY OF THE INVENTION 
     This invention is directed to apparatus and methods of recovering hydrocarbonaceous and additional products from oil/tar sands. The method includes the steps of forming a hole in a body of oil or tar sand, positioning an apertured sleeve within the hole to minimize fill-in of the sand, positioning a gas inlet conduit into the apertured sleeve, and introducing a heated, pressurized processing gas into the sleeve through the gas inlet conduit, such that the heated, pressurized processing gas penetrates into the sand through the apertures, thereby converting bitumen within the sand into hydrocarbonaceous products. The processing gas and hydrocarbonaceous products are withdrawn as effluent gas through the hole. In the preferred embodiment, one or more initial condensation steps are performed to recover crude-oil products from the effluent gas, followed by one or more subsequent condensation steps to recover additional, non-crude-oil products from the effluent gas. 
     The apertured sleeve may be installed in sections into the hole as the hole is formed. The apertures in the sleeve may be holes with a circular or other geometry or elongate cuts. In particular, the apertures in the sleeve are elongate cuts oriented more vertically than horizontally; that is, more aligned with the axis of the sleeve. A mesh screen may be supported between the apertured sleeve and the body of oil or tar sand. 
     The additional recovered products may include ethane, propane, butane, carbon dioxide, methane, nitrogen, or hydrogen, depending upon the type of processing gas, the nature of the crude-oil products, contamination in the well, and other factors. To create the processing gas, a fuel may be burned to produce an exhaust gas and heat used to heat a heat exchanger. At least a portion of the exhaust gas may be routed through the heat exchanger to produce the processing gas. To enhance efficiency, to reduce environmental impact, or to lower the oxygen content of the processing gas, at least one of the additional products may be mixed with the exhaust gas as make-up for the processing gas. According to a preferred embodiment, the composition of the processing gas may be adjusted so that it contains approximately 1 percent oxygen or less. 
     The subsequent condensation steps may be carried out in at least one cooled chamber having an input and an output, and a compressor system may be provided at the output of the cooled chamber to maintain the effluent gas at a negative pressure from the hole and through the initial and subsequent condensation steps. The cooled chamber preferably includes a plurality of critical orifices sized to recover the additional products. The chamber may be cooled with liquid carbon dioxide or other liquids or techniques, including carbon dioxide recovered from the effluent gas stream. 
     The crude oil products are typically recovered as a ratio of heavy crude to lighter crudes, in which case the flow rate of the processing gas may be adjusted to reduce the ratio. Alternatively, the reflux time of the heavy crude with respect to the initial condensation step may be increased to reduce the ratio. For that matter, one or more of the following parameters may be adjusted in accordance with the invention to vary the recovery of crude oil, other products or contaminants from the effluent gas: 
     the temperature, pressure or flow rate of the processing gas, 
     the residency time of the processing gas in the hole, 
     the reflux time of the crude oil with respect to the initial condensation step. 
     A basic system according to the invention for recovering hydrocarbonaceous and other products from a hole formed in oil or tar sand, comprises: 
     a combustor for heating and pressurizing a processing gas; 
     an apertured sleeve disposed within the hole to minimize fill-in of the sand; 
     a gas inlet conduit for introducing the processing gas into the sleeve to convert bitumen in the sand into hydrocarbonaceous products; 
     a gas outlet conduit for withdrawing the processing gas and hydrocarbonaceous products from the hole; 
     an initial condenser system for recovering crude oil products from the effluent gas; and 
     a subsequent condenser system for recovering additional products from the effluent gas. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a schematic drawing showing improvements to both the injection and collection sides of a well; 
         FIG. 2  is a detail drawing of a third condenser unit; 
         FIG. 3  is a simplified drawing of a casing applicable to oil and tar sand extraction operations. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     In common with the teachings of U.S. Pat. No. 7,048,051 (“the &#39;051 patent”), this invention is directed to the extraction of hydrocarbonaceous products utilizing a single well for the introduction of processing gas and product extraction. The system and method are applicable to recovery from oil sands and tar sands as described in further detail herein. 
     Referring now to  FIG. 1 , a hole  22  is drilled through an overburden  32  and into an oil-containing body or formation  34  to be treated. A processing gas inlet conduit  20  is disposed within hole  22 . Preferably, the conduit  20  is constructed of a heat conductive and refractory material (for example, stainless steel) which is capable of withstanding temperatures of up to 2000° F. or greater. The processing gas inlet conduit  20  is preferably positioned within hole  22  by a distance of at least about twice the diameter of the conduit  20 . An effluent gas conduit  26  is positioned around the opening of the hole  22  for receiving an effluent gas from which hydrocarbonaceous and other products are obtained. 
     In oil shale, kerogen is cracked, which has a molecular weight on the order of 1000 Daltons or greater. With oil and tar sands, however, bitumen is cracked, which has a molecular weight of about half that of kerogen. In fact, when cracking kerogen, a transition occurs from kerogen to bitumen to oil products. As such, with oil and tar sand an initial high-temperature cracking and gasification step is not necessary. Temperatures on the order of 600° F. to 800° F. are useful as opposed to the 1200° F. to 1600° F. used for kerogen cracking and gasification. 
     Referring to  FIG. 3 , for oil/tar sand applications, a central, in-well pipe  402  with apertures  404  would be placed during the drilling operation. The apertures  404  may include small holes, diagonal cuts, mesh features, and so forth, depending upon material composition and potential flow rate. For example, perforations on the order of an inch or thereabouts would be provided throughout the length of the pipe and, behind that (against the sands) a screen  410  with much smaller opening would be used. The holes may be cut into the pipe at a vertical angle to restrict sands from falling back into the well hole. Materials similar to window screen could be used, though high-integrity (i.e., “304”) stainless steel would preferably be used for construction. 
     To sink the well, a flat coring bit may be used, with the casing just described following directly behind that. The casing would be installed during the drilling process. The material removed during the drilling process would be pumped up through the casing. When the coring bit reaches its destination, it remains in position with casing situated above it. 
     Processing Gas Considerations 
     In the case of the &#39;051 patent, the pressurized processing gas is air, which is heated by burning a combustible material introduced into combustor  16  through a supply conduit. The air is drawn from the ambient environment, compressed and delivered to the combustor by way of a gas conduit. While a recycling conduit may be provided between the gas conduit and the combustor  16  to facilitate the optional recycling of a portion of the gaseous fraction of hydrocarbonaceous products to the combustor  16 . Although a mechanism can be provided for recycling a portion of the waste inorganic gas (which contains carbon dioxide) to the compressor  12  so as to augment the concentration of carbon dioxide in the processing gas, no details are provided with regard to carrying this out. 
     The instant invention improves upon previous configurations by relying largely on gases other than air as the processing gas. Continuing the reference to  FIG. 1 , air and fuel enter the combustor where the fuel is burned, generating heat in a heat exchanger. Although the burner and heat exchanger are drawn as two separate boxes, they may be integrated as disclosed in the &#39;051 patent. The primary gas flow entering the heat exchanger is the exhaust from the combustor itself. The circulation of the exhaust gas through the heat exchanger results in a closed-loop process that not only increases efficiency, it also provides an oxygen-deprived reduction environment in the extraction well. 
     In the preferred embodiment, the fuel used for the combustor is at least partially derived from the effluent gas stream through processes described elsewhere herein. As such applicable fuels may include straight or mixtures of methane, ethane, propane, butane, and or hydrogen and so forth. Air is used only as a “make-up” gas into the heat exchanger, and the level of make-up air may be adjusted so that gas used for extraction has an oxygen of 1 percent or less. The lower oxygen content in the processing gas is advantageous for several reasons. For one, higher levels of oxygen can auto-ignite down at the bottom of the well. In particular, oxygen content may be adjusted by changing the fuel mixture of the combustor to achieve a very rich fuel mixture, thereby diminishing the level of oxygen. Oxygen sensors in communication with conduits  20  and  26  are preferably provided to monitor O 2  content into and out of the well to maintain desired operating conditions. 
     Like all burners, the combustor may only be 60 to 80 percent efficient. However, a boiler may be used to create steam, with the waste heat being used to run a turbine to create electricity as needed for different on-site operations. 
     Multi-Stage Condensation 
     An effluent gas conduit  26  is positioned around the opening of the hole  22  for receiving an effluent gas which includes the processing gas and hydrocarbonaceous products formed from the pyrolysis of kerogen. The effluent gas conduit  26  further serves to transfer the effluent gas to above-ground condenser units. The &#39;051 patent discloses a single condenser that collected products emerging from the well as a vapor at standard temperature and pressure (STP). The liquid fractions of the hydrocarbonaceous products were removed from the bottom of the condenser; however, those portions that were or could not be condensed into a liquid at STP were vented to the atmosphere. 
     This invention improves upon the collection side of the system as well through multiple stages of condensation, with the goal being to recover all liquid and gaseous products. 
     The preferred embodiment incorporates three stages of condensation. The first stage collects only the heavy crude. The second stage collects the light and medium crudes and water; the last stage collects gaseous products, including methane, ethane, propane, butane, carbon dioxide, nitrogen and hydrogen. As with the reduced-oxygen processing gas improvements described earlier, the use of multiple condensation stages is considered patentably distinct. That is, while the combination of the processing gas improvements and multiple condensation stages achieves certain symbiotic benefits in combination, the improvements to the injection side and the collection side of the well may be used independently of one another. This third condenser stage, in particular, is applicable to industries outside of the petroleum industry; for example, the general gas industry, the chemical industry, and others. 
     Cooling coils are typically used in the first two condenser stages. The invention is not limited in this regard, however, in that other known devices such as coolant-filled ‘thumbs’ may alternatively be used. All of the products recovered by condensers one and two are liquid products at STP. In the oil industry heavy, medium and light crudes are separated by API numbers, which are indicative of density. Heavy crude is collected from condenser #1, whereas light and medium crudes are collected by condenser #2. The light crude comes out with water, which is delivered to an oil-water separator known in the art. The heavy crude is preferably pumped back into a reflux chamber in the bottom half of condenser #1 to continue to crack the heavy crude and recover a higher percentage of sweet and light crude products. This also creates more gas products in condenser #3. 
     As flow rate is an important consideration in condensation, a distinction should be made between CFM (cubic feet per minute) and ACFM, or actual CFM, which takes temperature into account. At 600° F., the temperature of the processing gas entering the well could have a flow rate of approximately 500 ACFM. Exiting the well the temperature will be near 600° F. but the flow rate could reach as high as 1000 ACFM depending on product content. Once the liquid products are removed and the gases get cooled down to 60° for condensation purposes, the flow rate gets reduced to approximately about 100 ACFM. These considerations are particularly important in the last condenser stage, which uses pressure loops and critical orifices to recover the individual gaseous products. 
       FIG. 2  is a detail drawing that focuses on the final stage of condensation. The condenser unit is actually a set of condensers enabling various components to be divided out in terms of temperature and pressure on an individualized basis. Condenser #3 includes a sealed, insulated housing filled with a coolant, preferably liquefied CO 2 . Conveniently, the liquid CO 2  is recovered by condenser #3 itself, as described in further detail below. 
     The inside of condenser #3 is maintained at a temperature of about −80 to −100° F. from the liquid carbon dioxide. Immersed in the liquid CO 2  are a series of loops, each with a certain length, and each being followed by a critical orifice that establishes a pressure differential from loop to loop. The length of each loop establishes a residency time related to the volume of the individual components within the gas mixture. 
     Each loop between each set of orifices is physically configured to control the pressure in that loop as a function of the temperature within the condenser, causing particular liquefied gases to become collectable at different stages. In  FIG. 2 , loop  202  and critical orifice CO1 are configured to recover propane and butane, which is collected at  210 . Loop  204  and critical orifice CO2 are configured to recover CO 2  which is collected at  212 . Loop  205  and critical orifice COn are configured to recover methane, which is collected at  213 . Loop  206  and critical orifice COf are configured to recover nitrogen, which is collected at  214 . Following the final critical orifice, COf, hydrogen is recovered. A compressor  216  not only compresses the collected hydrogen gas into a tank, in conjunction with product condensation and removal it creates a negative pressure back up the line, between condensers #2 and #3, and all the way down into the well. The significance of this negative pressure will be addressed in subsequent sections. 
     The purity of the collected gaseous products may vary somewhat. Methane, for example, is quite pure, and the hydrogen is extremely pure. All of the gaseous products are collected in the liquid state, and all are maintained as liquids except hydrogen, which emerges as a gas and it not compressed into a liquid (although it could be). The propane may be mixed with butane, and may be kept as a combined product or separated using known techniques. To assist in the recovery of the gaseous products into a liquefied state, there is an initial storage tanks for these products built into the condenser or at least physically coupled to the condenser to take advantage of the cooled CO 2  from where the recovered products are then pumped into external pressurized storage tanks. 
     The only materials which pass through the critical orifices are in the gaseous state. In terms of dimensions, the input to condenser #3 may have a diameter on the order of several inches. The critical orifices will also vary from ⅛″ or less initially down to the micron range toward the output of the unit. 
     As mentioned, the coal of this aspect of the invention is recover all products on the collection side of the well and, in some cases, use those products where applicable for processing gas formation or product collection. In addition to the collected liquid CO 2  being used to cool condenser #3, the combustible gases may be used to run the combustor, particularly if the combustor has a BTU rating which is higher than necessary. For example, if the combustor needs a BTU in the 1000 to 1100 BTU range, combustible gasses like propane and butane collected from compressor #3 may be mixed with recovered combustible gases such as low BTU gas like hydrogen or an inert gas like nitrogen to achieve this rating. 
     In terms of dimensions, condensers #1 and #2 may be on the order of 4 feet in diameter and 20 feet long, whereas compressor #3 may be 2+ feet by 8 feet, not including the compressors or the tanks. All such sizes, pipe diameters, and so forth, are volume dependent. Whereas, in the preferred embodiment, the injection and collection equipment may be used for multiple wells, such as 16 wells, but they could used for more or fewer with appropriate dimensional scaling. 
     Physical aspects of condenser #3 will also vary as a function of the installation; in other words, the actual size of the loop within each phase may vary as a function of gas content which might be site-specific. Accordingly, prior to operation if not fabrication, an instrument such as an in-line gas chromatograph may be used to determine the composition of the flow into condenser #3. The analysis may then be used to adjust the physical dimensions of the unit; for example, to construct a condenser which is specific to that site in terms of what products and/or contaminants are being produced. 
     Physical Parameter Adjustment 
     The combination of various physical parameters associated with the invention allows for a wide rage of adjustments in overall operation. As one example, assume that the system is producing an undesirable high percentage of heavy crude. Several things may be done to rectify such a situation. One solution is to slow down the flow rate of the processing gas being pumped down into the well, thereby increasing the residency time of the heated gas. Alternatively, the temperature of the processing gas may be increased to enhance cracking down in the well, thereby reducing the amount of heavy crude. As a further alternative, reflux time in condenser #1 may be increased. Such techniques may be used alone or in combination. 
     Indeed, according to the invention, various physical parameters may be adjusted to alter the ratio of products and/or the amount of gas collected in the end. These parameters include the following: 
     processing gas temperature; 
     processing gas pressure; 
     flow rate; 
     residency time; 
     reflux time; 
     condenser temperature; and 
     the negative pressure throughout the collection side of the system. 
     These parameters may be ‘tuned’ to maximize product output. However, such adjustments may have other consequences. For example, a higher processing gas residency time in the well might increase carbon monoxide production, which could lead to secondary effects associated with the liquids extracted, the oil liquid extracted, and/or the liquefied gases taken out of the third condenser. 
     The adjustment of physical parameters may also have an effect upon contaminant generation. Oil sands may contain elements such as sulfur or other contaminants or minerals. One advantage of the instant invention is that the well is operated at a very reducing environment, preferably less than 1 percent oxygen, such that reactions with materials such as sulfur are minimized. Nevertheless, the physical parameters discussed above may be adjusted to reduce the level of contaminants such as sulfur.