Patent Grant
8893793
The present invention relates generally to the recovery of hydrocarbonaceous products from oil shale and oil/tar sands and, in particular, to a process and system for recovering such products and byproducts with significantly reduced environmental impact.
The term “oil shale” refers to a sedimentary rock interspersed with an organic mixture of complex chemical compounds collectively referred to as “kerogen.” The oil shale consists of laminated sedimentary rock containing mainly clay with fine sand, calcite, dolomite, and iron compounds. Oil shales can vary in their mineral and chemical composition. When the oil shale is heated to above 250-400° F., destructive distillation of the kerogen occurs to produce products in the form of oil, gas, and residual carbon. The hydrocarbonaceous products resulting from the destructive distillation of the kerogen have uses which are similar to petroleum products. Indeed, oil shale is considered to be one of the primary sources for producing liquid fuels and natural gas to supplement and augment those fuels currently produced from petroleum sources.
Processes for recovering hydrocarbonaceous products from oil shale may generally be divided into in situ processes and above-ground processes. In situ processes involve treating oil shale which is still in the ground in order to remove the hydrocarbonaceous products, while above-ground processes require removing the oil shale from the ground through mining procedures and then subsequently retorting in above-ground equipment. Clearly, in situ processes are economically and environmentally desirable since removal of the oil shale from the ground is often expensive and destructive. However, in situ processes are generally not as efficient as above-ground processes in terms of total product recovery.
Historically, prior art in situ processes have generally only been concerned with recovering products from oil shale which comes to the surface of the ground; thus, prior art processes have typically not been capable of recovering products from oil shale located at great depths below the ground surface. For example, typical prior art in situ processes generally only treat oil shale which is 300 feet or less below the ground surface. However, many oil shale deposits extend far beyond the 300 foot depth level; in fact, oil shale deposits of 3000 feet or more deep are not uncommon.
Moreover, many, if not most, prior art processes are directed towards recovering products from what is known as the “mahogany” layer of the oil shale. The mahogany layer is the richest zone of the oil shale bed, having a Fischer assay of about twenty-five gallons per ton (25 gal/ton) or greater. The Mahogany Zone in the Piceance Creek Basin consists of kerogen-rich strata and averages 100 to 200 ft thick. This layer has often been the only portion of the oil shale bed to which many prior art in situ processes have been applied.
For economic reasons, it has been found generally uneconomical in the prior art to recover products from any other area of the oil shale bed than the mahogany zone.
Thus, there exists a relatively untapped resource of oil shale, especially deep-lying oil shale and oil shale outside of the mahogany zone, which have not been treated by prior art processes mainly due to the absence of an economically viable method for recovering products from such oil shale.
Another important disadvantage of many, if not most prior art in situ oil shale processes is that expensive rubilization procedures are often necessary before treating the oil shale. Rubilization of the in situ oil shale formation is typically accomplished by triggering underground explosions so as to break up the oil shale formation. In such prior art process, it has been necessary to rubilize the oil shale formation so as to provide a substantial increase in the permeability of the oil shale bearing rock formation. By increasing the permeability, the ability for gases and liquids to flow also increases, the potential to recover a more substantial portion of products therefrom. However, rubilization procedures are expensive, time-consuming, and often cause the ground surface to recede so as to significantly destroy the structural integrity of the underground formation and the terrain supported thereby. This destruction of the structural integrity of the ground and surrounding terrain is a source of great environmental concern.
Rubilization of the oil shale in prior art in situ processes has a further disadvantage. Upon destructive distillation of the kerogen in the oil shale to produce various hydrocarbonaceous products, these products seek the path of least resistance when escaping through the marlstone of the oil shale formation. By rubilizing the oil shale formation, many different paths of escape are created for the products; the result is that it is difficult to predict the path which the products will follow. This, of course, is important in terms of withdrawing the products from the rubilized oil shale formation so as to enable maximum recovery of the products. Since the products have numerous possible escape paths to follow within the rubilized oil shale formation, the task of recovering the products is greatly complicated and significant sub surface environmental issues become more of an issue. Including significant groundwater contamination.
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 the United States, 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.
Certain improvements with respect to the recovery of products from shale are disclosed in U.S. Pat. No. 4,928,765. Unlike other prior art processes, the in situ body of oil shale to be treated is not rubilized. Rather, a gas-fired heater assembly is placed within a bore hole followed by the introduction of fuel gas and combustion air from above ground, both of which are regulated to maintain an initial start-up temperature of over 1000° F. and thereafter a constant temperature of below 1500° F. throughout a reaction zone formed in the surrounding shale bed. Specifically, a production temperature of 1200° F. was been found most desirable. By maintenance of this temperature, voids created in the reaction zone as kerogen is retorted to evolve natural gas, become black body radiators assisting to ensure a sustained, constant high volume extraction of natural gas devoid of any liquids.
Like all mining and non-renewable resource development projects, oil shale and 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.
This invention is directed to apparatus and methods of in situ recovering hydrocarbonaceous and additional products from nonrubilized oil shale and oil/tar sands. The method comprises the steps of forming a hole in a body of nonrubilized oil shale or sand, placing a heating source into the hole, and introducing a conductive and radiant non-burning thermal energy front sufficient to convert kerogen in oil shale or bitumen in oil sand to hydrocarbonaceous products.
The subsequent produced gases and hydrocarbonaceous products are withdrawn as effluent gas through the hole, and a series of condensation steps are performed on the effluent gas to recover various products. In the preferred embodiment, a negative pressure relative to the well inlet pressure is maintained to insure positive flow of the combustion and product gases, this is performed by a method of blowers on the effluent side of the well and the removal of mass during the condensation steps. Also 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. In conjunction with oil/tar sands, the method includes the step of providing an slotted permeable well casing/sleeve within the hole to limit excessive in-fill.
Such additional products may include ethane, propane, butane, carbon dioxide, methane, or hydrogen, depending upon the nature of the crude-oil products, contamination in the well, and other factors. Within the preferred embodiment, the composition of the well gases may be adjusted so that it contains approximately 1 percent oxygen or less. This will be done by inert flushing and or oxygen getters.
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 between multiple compressor stages sized to recover the additional gaseous products. The chamber may be cooled with liquid carbon dioxide or other liquids or refrigerant techniques, including carbon dioxide recovered from the effluent gas stream.
A carbon sequestration step may be performed wherein recovered carbon dioxide is delivered down the hole following the recovery of the hydrocarbonaceous products. A plurality of well holes may be drilled, each with a gas inlet to receive a heated and pressurized processing gas. The processing gas and hydrocarbonaceous products may be withdrawn as effluent gas through each hole, and a plurality of condensation steps may be used to recover crude oil products and the additional products from the effluent gas from a plurality of the holes. The cracking and subsequent removal of hydrocarbonaceous products and associated gases opens the kerogen pores and significantly increases permeability in the now depleted oil shale rock. Once depleted these now vacant pores, having charred surface areas significantly greater than other carbon sequestration processes can now adsorpt large volumes of carbon dioxide. As part of a carbon sequestration process, carbon dioxide may be introduced down a central well hole following the recovery of the hydrocarbonaceous products until the carbon dioxide is detected at one or more of the surrounding holes, thereby indicating saturation. This now represents a potentially significant increase in carbon sequestration potential over other techniques.
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:
A basic system for recovering hydrocarbonaceous and other products from a hole drilled in nonrubilized oil shale and oil/tar sands comprises:
This invention is directed to the extraction of hydrocarbonaceous products from nonrubilized oil shale. The system and method are also applicable to recovery from oil sands and tar sands with appropriate engineering modification described in further detail herein.
Referring now to
If a combustion heater is used, the fuel 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 combustor or from the blower, and the level of make-up air may be adjusted so that gas used for extraction has an oxygen content 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 are preferably provided to monitor O2 content into and out of the well to maintain desired operating conditions.
The exhaust of the down hole combustor will be exhausted separately and 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 and the exhaust can be used as make-up air.
An effluent gas conduit 26 is positioned around the opening of the hole 22 for receiving an effluent gas which includes hydrocarbonaceous products formed from the pyrolysis of kerogen and can include the process combustion gases. The effluent gas conduit 26 further serves to transfer the effluent gas to above-ground condenser units. 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.
The effluent 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 1000° F. to 1400° F., the gases exiting could reach flow rates as high as 2000 ACFM depending on well depth and product content. Once the liquid products are removed and the gases get cooled down to 80° for condensation purposes, the flow rate gets reduced to approximately about 200 ACFM. These considerations are particularly important in the last condenser stage, which uses pressure loops and critical orifices to recover the individual gaseous products.
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 CO2 are a series of loops, each with a certain length, and each being followed by a critical orifice and a compressor loop that establishes a pressure differential from loop to loop. The length and diameter 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 and compressor loops 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
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 CO2 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 goal 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 CO2 being used to cool condenser #3, the combustible gases may be used to run the down hole 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.
Referring back to
Oil shale is present in various strata, with significant horizontal permeability and very little vertical permeability. The horizontal permeability of one layer might be quite different from the permeability of other layers. The use of compressor 216 in conjunction with pressure differentials across the condensers, establishes a negative pressure all the way down into the well. As vapor molecules leaving the well are pulled across the face of the rock, a Venturi effect is created that effectively draws the now heated kerogen out of these horizontally permeable strata. This action improves extraction, facilitating an active rather than passive collection of products.
The combination of various physical parameters associated with the invention allows for a wide range 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. Excess heavy crude may means that the kerogen is not being cracked as efficiently as it could be. One solution is to slow down the flow rate of the effluent gases thereby increasing the residency time of the heated gas. Alternatively, the temperature of the heater 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:
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 shale is a compressed organic material which contains elements such as sulfur from pyrite 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.
Another advantage made possible by the invention is the opportunity for large-scale carbon sequestration. Certain existing carbon sequestration processes simply fill abandoned mines with carbon dioxide which, being heavier than air, ideally remains in place. However, cracks and fissures may exist or develop, allowing the gas to leak out. In addition, the large surface area of the mine is not used directly, thereby reducing the potential efficiency of the sequestration process.
According to this invention, when kerogen is cracked and removed from the wells recovery cylinder, the remaining product at high temperature exhibits a vast system of micropores that are coated with char. Resulting in an enormous surface area which allows for the direct adsorption of carbon dioxide. Accordingly, following a mining operation, carbon dioxide may be pumped down into the well to be adsorped by these porous materials.
During this process, the uncapped wells around the injection well will be monitored, and when a sufficient level of CO2 is detected, a desired level of saturation can be determined. Again, the CO2 used for injection may be derived from the system itself, through the output of condenser #3, described above. As such, the CO2 may be injected in liquid form. Overall, it may be possible to achieve a 70 to 80 percent replacement of volume for the cracked kerogen removed which would relate to multiple equivalent volumes of CO2 by mass.
The systems just described may be useful not only in oil shale, but also in oil/tar sands with appropriate engineering modification. In oil shale, kerogen is cracked, which has a molecular weight on the order of 1000 Daltons or greater. With oil and tar sands bitumen is being 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. The first condenser described above may therefore be unnecessary.
In contrast to oil shale, oil/tar sands are generally not stratified but instead exhibit omnidirectional permeability. As such the use of the Venturi effect discussed above is not available. Additionally, since sands ‘flow,” provisions need to be made for the well casing to ensure against fill-in.
According to the invention, for oil/tar sand applications, a central, in-well pipe 402 with apertures 404 would be placed during the drilling operation. The apertures 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 or punched 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 type-304 stainless steel would preferably be used for construction.
To sink the well, a flat coring bit would 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. At this point the heater is lowered into the casing with conduits attached.
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| Number | Date | Country | |
|---|---|---|---|
| 20110198083 A1 | Aug 2011 | US |
