PRODUCTION OF LOWER MOLECULAR WEIGHT HYDROCARBONS

The present invention relates generally to processes for upgrading (cracking and hydrogenation) of high molecular weight hydrocarbons using a catalytic composition at moderate temperatures, methods for stabilizing the upgraded product, and methods for reducing carbon oxides using a catalytic composition.

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Description
PRIORITY DATA

This application claims priority of U.S. Provisional Application No. 60/826,035, filed Sep. 18, 2006, which is incorporated by reference herein.

FIELD OF THE INVENTION

The present invention relates generally to processes for upgrading (cracking and hydrogenation) of high molecular weight hydrocarbons using a catalytic composition at moderate temperatures, methods for stabilizing the upgraded product, and methods for reducing carbon oxides using a catalytic composition.

BACKGROUND OF THE INVENTION

The upgrading of viscous high molecular weight hydrocarbons to form lower viscosity, lighter weight molecular hydrocarbon mixtures has long been studied. Traditionally, this involved the cracking and hydrogenating of the hydrocarbon molecules that make-up the high molecular weight viscous material at extremely high temperature and pressure. To improve the efficiency of this process, the inventor of the subject application developed a process for upgrading these viscous materials under substantially less rigorous conditions. The process involves contacting an aqueous catalytic composition with high molecular weight hydrocarbons to produce a lower molecular weight hydrocarbon product, and recovering the lower molecular weight hydrocarbon product. The catalytic composition comprises cement (preferably Portland cement), a volcanic ash component, titanium dioxide, and a transition metal salt. This work and publications related to upgrading and to other aspects of the invention is described in U.S. Publication No. 2004/0016676 A1 published on Jan. 29, 2004, the disclosure of which is incorporated by reference herein. While the invention set forth in such publication represents a major economic and technical breakthrough, in certain instances drawbacks have become evident.

More particularly, it has been discovered that the specific catalyst composition described does not consistently give optimum results for all forms of heavy oil and bitumen structures and further that the viscosity and density of the product produced is not uniformly stable over an extended period.

SUMMARY OF THE INVENTION

It has now been discovered that markedly improved viscosity reduction and improvement in product composition can be achieved in the upgrading process described in U.S. Patent Publication No. 2004/0016676 by modifying the catalytic composition and the process conditions used in the upgrading process. With respect to the catalytic composition precursors, increased amounts of the volcanic ash component and decreased amounts of cement are used. The temperature used in the upgrading process is preferably from about 50° C. to about 200° C. and more preferably from about 75° C. to about 110° C., in contrast with the ambient temperatures used in the Examples of applicant's prior publication.

It has further been found that the product of the process of the invention can be further improved by subjecting the product of a first treatment with the aqueous catalytic composition to additional treatments, with or without the addition of a diluent (e.g., a hydrocarbon based solvent), to further upgrade the product. This technique may be done under the same or less rigorous conditions as the first treatment and is of particular value with certain high molecular weight hydrocarbon feed stocks, such as heavy oil and bitumen.

Another embodiment of the invention is the discovery of techniques that stabilize, i.e., hold substantially constant the viscosity and/or density, of the upgraded product. These techniques include adding a diluting hydrocarbon to the product of the upgrading reaction. Preferably, the diluent is added in an amount ranging from about 5 to about 15% by weight based upon 100% total weight of the lower molecular weight hydrocarbon. These stabilizing techniques are useful in all types of oils but are particularly useful in heavy oils and bitumen that have higher polar (resin), aromatic, and asphaltene contents. The amount of diluent added can be selected to achieve a desired concentration of low molecular weight hydrocarbon product suitable for the intended transportation method (e.g., pipeline transport or trucking specification).

A still further finding is that the presence and/or the addition of carbon dioxide (CO2) to the process produces reaction products greatly reduced in carbon oxides, enhances viscosity and density reduction, and stabilizes the product (e.g., stabilizes the density and/or viscosity of the product). Heavy oil frequently contains entrained carbon dioxide from the oil formation or from injection of carbon dioxide into the well to increase production. The heavy oil used in the tests discussed below contained up to about 5% entrained carbon dioxide. By converting the entrained carbon dioxide into useful hydrocarbon products, the inventive method creates valuable hydrocarbon products from carbon dioxide that is a disposal and environmental liability otherwise.

The inventive method can also convert carbon oxides from other sources (such as the burners used to heat the oil-in-water emulsion for the upgrading process of the present invention, as well as exhausts from coal burning furnaces, Fischer-Tropsch systems for the generation of hydrogen (H2), and natural gas burning) into useful organic compounds without inhibiting the upgrading process. When carbon oxides are added to the process or are inherently present in the high molecular weight hydrocarbon feedstock, the organic compounds (e.g., hydrocarbons and alcohols) generated by the conversion reaction enhance the upgrading process by acting as an additional diluent to increase the API value of the lower molecular weight hydrocarbon product.

Additionally, it has been discovered that the catalytic composition, such as described herein and in the inventor's prior publication, can, in an aqueous mixture or emulsion, convert carbon oxides, most specifically carbon dioxide, to organic compounds free or substantially free of such carbon oxides. This conversion process can be performed in the presence or absence of hydrocarbons (such as high molecular weight hydrocarbons and lower molecular weight hydrocarbons). The aqueous catalytic composition can be prepared, for example, by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts an overview of one illustrative embodiment of the inventive method for upgrading high molecular weight hydrocarbons and converting carbon oxides to light hydrocarbons.

FIGS. 2-5 are scanning electron microscope photographs of the particles suspended in the aqueous catalytic composition.

 DETAILED DESCRIPTION OF THE INVENTION

The upgrading process of the invention is carried out at relatively moderate temperature (preferably less than about 200° C. and more preferably less than about 150° C.) in the presence of an aqueous catalytic composition. The pressure utilized is generally ambient or subject to whatever pressure may build up from the pumping of fluids and other inherent process steps. External pressurization is generally not required. However, when desired, external pressurization may be achieved by introducing an external pressuring gas, such as carbon dioxide and/or a hydrocarbon gas. According to one embodiment, the process is performed at approximately three atmospheres to maintain the flow of the emulsion. The process is applicable to both surface upgrading of heavy oils and bitumen and subsurface enhanced recovery applications of heavy oil and bitumen. Optionally, this process can be adapted to convert carbon oxides, such as carbon dioxide and carbon monoxide, to light hydrocarbons, alcohols, and/or other organic compounds. The carbon oxide conversion can actually enhance the upgrading function by providing additional diluent low molecular weight hydrocarbons and/or alcohols to increase the API value of the high molecular weight hydrocarbons and providing stability to the upgraded product.

This inventive cracking and hydrogenation process, though operating at higher temperatures than Applicant's prior work, still operates at a more moderate temperature and pressure than the conventional cracking and hydrogenation processes. Furthermore, in contrast to the conventional cracking and hydrogenation processes little or no residual carbon dioxide or carbon monoxide is released into the atmosphere, because the inventive process converts these oxides.

Surprisingly, the aqueous catalytic composition performs the cracking and hydrogenation without any substantial “gumming” or coating of the surfaces of the aqueous catalytic particles in the oil-in-water emulsion. The advantage of substantial coking permits the process to operate continuously. Also the process results in complete or partial desulfurization by reduction of the sulfur-containing species. Sulfur species pose a significant problem in the oilfield industry, because many feed stocks, such as tar, tar sands, heavy crude, shale oil, and bitumens, contain high sulfur levels that cause pollution, corrosion and undesired results in the refining process (e.g., with refinery catalysts).

The process of the present invention can convert high molecular weight hydrocarbons having an API value of from 8 to 12 (and generally a viscosity higher than 350 cS at about 7° C.) to lighter molecular weight hydrocarbons having an API value of greater than 23 (for example, from 23 to 33).

If the resulting admixture of the high molecular weight hydrocarbon and aqueous catalytic composition does not have a significant percentage of carbon oxides, additional carbon oxides may be added until the admixture contains between 2 and 5 weight percent (or more) carbon oxide. Typically, greater than 25% of the total carbon oxide is converted to light hydrocarbons.

The carbon oxides may be converted to light hydrocarbons and/or other organic compounds, e.g., low molecular weight alcohols (methanol, ethanol and n- and iso-propanol) by adding the carbon oxides to an aqueous catalytic composition or an admixture of the aqueous catalytic composition and a liquid hydrocarbon. The carbon oxides are added under conditions of temperature and pressure sufficient to convert them to the organic compounds. The aqueous catalytic composition for this conversion is prepared by admixing and reacting a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide in an aqueous solution. For maximum effectiveness, the particles should have a Blaine grain fineness of at least 3000.

Additionally, the inventive catalyst can be used for the conversion of coal to liquid hydrocarbons using processing temperatures 25° to 50° C. higher than those described above for the liquid hydrocarbons. The coal is first crushed to facilitate its suspension in the aqueous system prior to being fed thereto. Coal is a very complex hydrocarbon with a very low hydrogen to carbon ratio compared to other liquid and semi-liquid hydrocarbons. The process for converting coal to liquid hydrocarbons is essentially the same as for the high molecular weight hydrocarbons described above, however, coal requires more energy due to the complex hydrocarbon bonds and the low hydrogen to carbon ratio. However, even with coal's greater energy requirements, this process is a very economical method of producing hydrocarbons from coal without producing a carbon oxide gas intermediate.

The inventive process may also be used in down-hole or subsurface enhanced recovery applications (e.g., for oil and bitumen). Applications of the process can be considered in steam or heat driven systems and in combination with carbon dioxide injection in unconsolidated reservoirs at depths of less than 1000 meters.

Furthermore, there should be no negative environmental consequences to the disposal of the used aqueous catalytic composition when it is not reusable. According to current laboratory data, virtually all of the carbon atoms introduced into the process employing the inventive method to upgrade high molecular weight hydrocarbons remain in the upgraded hydrocarbon output stream. This includes any carbon atoms introduced from the high molecular weight hydrocarbon, any added or formed diluent hydrocarbon, and any additional carbon added from streams such as carbon dioxide or carbon monoxide streams. Upgrading is accomplished by hydrogen addition, not carbon elimination.

The inventive process has a low requirement for natural gas to provide system heating. The maximum temperature needed is less than about 200° C.±20° C. and preferably less than about 110° C.±20° C. If the system is being applied to an oil-water emulsion that is naturally hot, above 75° C., then the intrinsic heat in the incoming emulsion is all that is required for the process to work efficiently.

There is no requirement for the addition of methane or other hydrocarbons as a source of hydrogen for the cracking and hydrogenation. The produced water and/or fresh water (whichever is available) in the emulsion provides the source of hydrogen.

Two to three times more, by weight, of light hydrocarbon compounds are contained in the treated (or upgraded) oil than in the untreated oil, with the same amount of diluent hydrocarbon having been added to each. This has a significant positive impact on the value of the treated crude oil.

There are significant reductions in the aromatic and polar (resin) fractions of the upgraded oil, with concurrent and significant increases in saturated and paraffins fractions. The bromine number measured during the pilot test was reduced from 3.0 in the untreated oil to 2.2 in the treated oil. The 15° C. pour point of the untreated oil was reduced to −51° C. in the treated oil. This indicates a great degree of positive chemical change.

For hydrocarbons having a boiling point above 260° C., using the SAPA analysis as a basis, there are typically significant reductions in the aromatic, polar (resin), asphaltene, and saturate fractions of the upgraded oil, with concurrent and significant increases in saturates or paraffin fraction. There is also typically a decrease in the aromatic fraction in the boiling point temperature range of 0° C. to 260° C. using the PNA analysis as a basis. The bromine number measured during the various pilot tests to date has been always reduced, which is an indication of a reduction of unsaturated bonds. The pour point of the untreated oil is significantly reduced in the treated or upgraded oil compared to the untreated oil. These test results indicate a great degree of positive chemical change.

Catalytic Composition

The catalytic composition used in practicing the invention is an aqueous admixture formed by reaction in water certain inorganic components referred to herein as “precursors” or “precursor components.” This admixture of active catalytic components in water is generally referred to herein as the “aqueous catalytic composition.” The admixture can be a slurry or suspension.

Generally, the precursor components for forming the catalytic composition include SiO2, Al2O3, Fe2O3, CaO, a transition metal salt, and titanium or boron oxide. Typical ranges of the precursors are shown in Table 1 below. All weight percents are based on the total weight of these active components when combined.

TABLE 1 Particulate Broad Range Preferred Component (wt. %) Range (wt. %) SiO2 10-60  25-50  Al2O3 2-20 6-20 Fe2O3 2-25 5-15 CaO 10-50  15-30  TiO2/B2O3 3-10 2-8  Trans. Metal Salt 3-20 3-10

Minor amounts of other compounds, such as magnesium and sodium oxide and calcium sulfate, may also be present without any deleterious effect.

An economical alternative to utilizing the compounds above in their pure form is to prepare the catalytic composition from composite materials to provide some or all of the components. For example, a cement and volcanic ash can provide the SiO2, Al2O3, Fe2O3, and CaO precursor components. Table 2 below illustrates the broad and preferred ranges of compositions using, in part, composites.

TABLE 2 Particulate Broad Range Preferred Component (wt. %) Range wt. % Cement 10-45  15-40 Component Volcanic Ash >50-85  55-80 TiO2 3-10 2-8 Transition 3-20  3-10 Metal Salt

The precursor components of the catalytic composition and the amounts thereof can be varied depending on the specific high molecular weight hydrocarbon feedstock being treated, whether significant conversion of carbon oxides is to take place, whether coal is being converted to liquid hydrocarbons, and the like. Optimization for each can be readily determined by simple experimentation. The starting materials are added to the water, i.e., SiO2, Al2O3, Fe2O3, CaO, a transition metal salt, titanium or boron oxide, a volcanic ash component, and a cement component. Sufficient water is added so that the dry weight of the precursor components in the aqueous catalytic composition is from about 4 to about 35 weight percent.

To form the catalytic composition, all of the active components must either be in an aqueous solution or in a particulate form. If in particulate form, the particles should preferably have a Blaine grain fineness of 3000 or more. Blaine grain fineness is a ratio of a particle's surface area (in square centimeters) to weight (in grams).

The cement component is preferably a Portland cement. Portland cements are mixtures of limestone and clay that have been ground and treated in a kiln from 1400 to 1600° C. About 24 wt. % of Portland cement by weight is calcium silicate and about 66 wt. % is CaO. Impurities can include up to about 3 wt. % of alumina, ferric oxide, and magnesia.

The volcanic ash component can be one or more of the following materials: scoria, pumice, tuff, e.g., tuffstone, mafic volcanic rock, e.g., ultramafic volcanic rock, pyroclastic rock, volcanic glasses, basalt or silica-based zeolites. Scoria is the most preferred. Scoria is the most common material in volcanic cones and is formed of small particles (about 1 cm across) of hardened volcanic lava. Scoria from the Washington/Oregon border is most preferred. It contains about 55% SiO2 and about 12% Fe2O3.

British Columbia scoria consists of about 46% SiO2, about 18% Fe2O3, about 8% CaO, and about 2.4% TiO2. Scoria from southern Mexico consists of about 79% SiO2 and about 6.6% Fe2O3. Mafic rock is defined as igneous rock which contains substantial quantities of silicates, such as pyroxene, amphibole, olivine, and mica. Ultramafic rock is a volcanic rock with an ultrabasic composition and over 90% composed of Fe·Mg minerals, predominantly olivine, orthopyroxene, and clinopyroxene. Volcanic glasses are called obsidian and consist of silica particles fused by the intense heat of a volcano. Basalt is a mafic, igneous rock composed of plagioclase. Different varieties of basalt differ in their degree of silica saturation. Zeolites are a family of aluminum silicate minerals that can occur naturally or be produced synthetically. Zeolites from British Columbia typically consist of about 89% SiO2, 0.8% Fe2O3, and about 1% CaO.

Any transition metal salt with a +2 or +3 oxidation state can be used as a precursor component of the catalytic composition. Preferred compounds include ferric chloride, ferrous chloride, and cobalt chloride. Ferrous chloride is the most preferred. The transition metal salt can be utilized in particulate or aqueous form. If used in aqueous form, only the weight attributable to the active component (the transition metal salt) should be considered in determining weight percents of the active components.

The titania useful as a component of the precursor composition exists naturally in four different forms: rutile (tetragonal), anatase (octahedrite), brookite (orthorhombic), and titanium dioxide (B) (monoclinic). While any of these forms of titania can be utilized with the present invention, the most preferred is the anatase form. Boron oxide (B2O3) can also be substituted and used in place of and in combination with TiO2.

The terms “high molecular weight hydrocarbon” and “low molecular weight hydrocarbon,” as used herein, are terms relative to one another. The former term signifies a mixture of hydrocarbons, with or without their entrained impurities, with an average molecular weight of the hydrocarbons significantly higher than the average molecular weight of the hydrocarbons in a lower molecular weight hydrocarbon. Thus, the use of the terms “high molecular weight hydrocarbon” and “low molecular weight hydrocarbon” does not signify any particular molecular weight ranges.

High molecular weight hydrocarbons are typically materials, such as crude oils, asphaltenes, tars, and heavy oils, which have limited or no practical use, but which can be converted to more valuable and useful lower molecular weight hydrocarbons via chemical means. Medium oils generally have resins or polar fractions less than about 25% of the weight of the total oil and have an API gravity of 22.3 to 32 with viscosities in the range of about 100 to 1000 centipoise; heavy oils generally have resins or polar fractions between about 25 and 40% of the total weight of the oil and have an API gravity of generally above 10 but less than 22.3 with viscosities greater than about 1000 centipoise; tars generally have resins or polar fractions greater than about 40% of the total weight of the oil and have an API gravity less than about 8 to 10 and a viscosity greater than about 8000 centipoise.

The lowest molecular weight hydrocarbons can include C1 to C4 gases, e.g., methane, propane, and natural gas. When these gases are present as part of the lower molecular weight hydrocarbon product, they impart an even higher API value.

The overall quality of the upgraded hydrocarbons is also improved as demonstrated by Saturates, Aromatics, Polars, and Asphaltenes (SAPA) and Paraffins, Naphthenes, and Aromatics (PNA) tests. These hydrocarbons and substrates can be treated on the earth's surface or in subsurface deposits at more moderate temperatures and pressures than conventional cracking and hydrogenation technologies.

In the case of highly viscous fuels, it may be advantageous to dilute the high molecular weight hydrocarbon with a lower molecular weight diluent hydrocarbon. The diluent can be a hydrocarbon such as refined and unrefined alkanes and cycloalkanes in the C5 to C25 range. Examples of readily available diluents include diesel fuel, naphtha, and diluent hydrocarbons from other refining processes which are rich in hydrocarbons in the C5 to C25 range. Condensate is a common example of an acceptable diluent hydrocarbon from other refining processes. Any hydrocarbon liquids with a boiling point below about 200° C. are also suitable. The composition of the diluent is not critical because it is primarily to reduce the viscosity of the heavy high molecular weight hydrocarbon feedstock to facilitate mixing with the aqueous catalytic combination. Of course, the diluent must not interfere with subsequent refining of the upgraded hydrocarbons. Even if the diluent is not substantially saturated it can be used, because the catalytic reaction can hydrogenate the non-saturated hydrocarbons. However, this can decrease the efficiency of the primary cracking and hydrogenation reactions.

Another method of enhancing the contact between the reactive particles in the aqueous catalytic composition and the high molecular weight hydrocarbon feedstock is to heat the latter to a moderate temperature such that it flows more freely. The amount of heat that can be added is constrained by the need to optimize the temperature of the reaction and economic considerations. Another consideration is the viscosity and thickness of the high molecular weight hydrocarbon to be treated; thicker, more viscous hydrocarbons require more heat than less viscous hydrocarbons. Of course, these two methods can be utilized together to achieve optimum results.

Preparation of the Catalytic Composition

The aqueous catalytic composition used in the experiments discussed below was made by the following method: An aqueous solution of about 33% (by weight) aqueous ferrous chloride solution was first mixed with the desired amount of water and, thereafter suitable amounts of particles of the other precursor components were added. The mixture was then thoroughly mixed to form the aqueous catalytic composition. Preferably, the resulting mixture contains about 15 weight percent of the precursors.

Composition of the Catalyst

The aqueous catalytic composition is significantly different than its precursor components. Several reactions occur within the aqueous mixture to form some known and some novel reactive colloidal minerals and compounds. The scanning electron microscope (SEM) images of the reactive particles found after the reaction characterize these particles. New crystal forms do not match any known crystalline structure. Specifically, the x-ray diffraction (XRD) spectrums of the crystalline structures were compared to known compounds having comparable empirical formulas. Based on the SEM images and XRD spectra, at least CaCO3 has formed new crystalline structures that do not match any known crystal structure.

The catalytic particles in the aqueous catalytic composition are mineral assemblages composed of silicate minerals and metal oxides. They have highly irregular, amorphous surface layers of transition metal oxides with micro-silicate mineral inclusions.

FIGS. 2 to 5 are SEM images of various reactive surfaces of the particles. These amorphous surfaces have various submicron sized cavities and indentations. Without being bound by any particular theory, applicant believes that these cavities and indentations are the active locations that facilitate the cracking and hydrogenation reactions.

The Upgrading of the Heavy Hydrocarbons

To initiate the cracking and hydrogenation reactions, the aqueous catalytic composition is brought into intimate contact with the high molecular weight hydrocarbon feedstock. The laboratory and pilot scale tests have demonstrated that optimal yield can be obtained by carefully adjusting the amount of the diluent hydrocarbon and the temperature of the mixing process. This is evidenced by the Saturates, Aromatics, Polars, and Asphaltines (SAPA) test and the Paraffins, Naphthalenes, and Aromatics (PNA) test. The water/heavy-oil or bitumen emulsion is preferably contacted with the aqueous catalytic composition at a temperature range of 50° C. to 200° C., and preferably 65° C. to 110° C. The cracking and hydrogenation reactions produce a chemically much-improved and a lighter crude oil product. The volume of diluent hydrocarbon added is preferably 40% to 50% less than what is normally required to reduce the viscosity to the typically required pipeline value of 280 cs at 7° C. In the pilot tests described below, it was found there was a 200% to 300% increase in the concentration of the 0° C. to 200° C. boiling point hydrocarbons after treatment as compared with the control of the comparably diluted untreated high molecular weight hydrocarbons.

In performing the inventive process, the aqueous catalytic composition to high molecular weight hydrocarbon loading can vary from a ratio of 2:1 to 4:1. The preferable loading ratio is about 3:1. This loading varies depending on the high molecular weight hydrocarbon being processed and the desired lower molecular weight hydrocarbon products. Simple experimentation can be performed to determine the optimal loading for a given set of high molecular weight hydrocarbon and desired products.

Where carbon oxides, e.g., CO2, is added to the feed, based on processing 300 barrels (bbls) per 24 hour day of the high molecular weight hydrocarbon feed, at least one standard cubic foot per minute (scfm) of the carbon oxide is added. Preferable amounts of 6 to 10 scfm or more may be added. Based on 1 bbl. of the high molecular weight hydrocarbon, broadly from 5 to 50 scft of carbon diooxide may be used.

In the examples described below, 3.5 to 7 scft/min of CO2 was feed to the 300 bbl/day of oil or 0.21 bbls/min to each of heavy barrel of oil. The rate of catalyst addition was such that each barrel of oil contained from 1.8 to 2.3 wt. % of the catalyst (based on the dry weight of precursors). Since a barrel of pure heavy oil weighs 350 pounds, there are 6.3 to 8.05 pounds of catalyst used per barrel or 1.32 to 1.69 pounds of catalyst for 0.21 barrels of oil. Accordingly, 3.5 to 7 scft of CO2 and 1.32 to 1.69 pounds of dry precursors were used for each 0.21 barrels of oil. Additionally, 0.63 barrels of water were also used in one minute.

Proportionate amounts of CO2 would be useful for processing greater of lesser amounts of oil. The optimum amount can be readily determined recognizing that the object is to avoid the substantial amounts of carbon oxides in the low molecular hydrocarbons and/or in the gaseous by-products. Use of lower amounts can be used, and such amounts shall, of course, be converted, thus achieving benefits of the invention. Excessive amounts will likely not be completely converted to organic products resulting in the presence of substantial amounts of the carbon dioxide in the low molecular hydrocarbons and/or in the gaseous by-products. The carbon oxides can be added as a gaseous or liquid feed. While the feed can be of a high purity, feeds having at least five percent or less of carbon oxides can be treated. Generally, 75% conversions of the carbon oxides can be obtained, though the process would be of great value with considerably lower conversions. In the absence of oil, the conversions are somewhat lower, say in the order of 50%.

FIG. 1 represents the semi-batch apparatus used for the pilot scale experiments discussed below to upgrade high molecular weight hydrocarbons and revert carbon oxides. The high molecular weight hydrocarbons are fed via line 112, pump 115, and line 117 to heat exchanger 140. Concurrently, water is fed from tank 120 through line 122, pump 125, and line 127 and diluent hydrocarbon is fed from tank 130 via line 132, pump 135 and line 137 to heat exchanger 140.

The mixture from heat exchanger 140 is fed through line 145 to static mixer 160 where it is contacted with aqueous catalytic composition from tank 150 fed via line 152, pump 155 and line 157. Optionally, carbon dioxide is fed from reservoir 170 through line 175. The heat exchanger is optional and only used if necessary to maintain stream 145 at approximately 65-110° C.

The output stream 165 of the static mixer is fed to a settling tank 180 where the mixture settles and forms distinct layers. The solids layer 196 contains the particles from the aqueous catalytic composition and any precipitates or other solid materials e.g., soils, sediments, rock mixtures and sands. Sulfur-based and metallic impurities present in the starting materials also form solid. The aqueous layer 192, formed above the solids layer 192 contains most water. Above the aqueous layer 192, is the hydrocarbon layer 188 containing lower molecular weight hydrocarbon products. Above the hydrocarbon layer 188, is the gaseous layer 184. The gaseous layer 184 typically contains light hydrocarbons that are not liquids at the operating temperature and pressure in the settling tank 180 as well as any other volatiles formed in the process.

The precipitated aqueous catalytic particles, which collected at the bottom of the pressure tank in the experiments described below did not become coated with carbon and based on x-ray diffraction (XRD) and scanning electron microscope (SEM) analysis, they may be reusable in the process.

EXAMPLE 1

The pilot scale examples were performed at a Steam Assisted Gravity Drainage (SAGD) pilot facility in the Cold Lake area of Alberta. The equipment used consisted of pumps, a pumper-mixer truck, a pressure tank, controls, instruments, and connecting pipes and hoses. The SAGD facility provided a produced water/oil emulsion input stream with an average split of 20% oil to 80% water to the pumper-mixer essentially configured as shown in FIG. 1 with the water/oil emulsion stream replacing the high molecular weight hydrocarbon source 110.

Between 9 m3 and 14 m3 of emulsion was processed in each experimental batch. The treatment was done in a continuous fashion. The Basic Solids and Water content (BS&W) of the treated oil stream ran from 1% to 5%. The solids content was less than 0.5%.

The control samples, marked Pilot Control 1, Laboratory Controls A, B, C and D were prepared to generate comparative data. Pilot Control 1 was performed in the pilot facility and the Laboratory Controls were performed in the laboratory. Oil from the same well and similar diluent hydrocarbons were used and mixed in various proportions that matched and exceeded the diluent-to-oil ratios used in the pilot facility. The oil used in Pilot Control 1 consisted of the oil alone with no added diluent hydrocarbon or aqueous catalyst composition. To the Laboratory Controls, both diluent hydrocarbon and aqueous catalyst composition were added.

The aqueous catalytic composition was prepared by mixing the following components in water in the percentages indicated:

TABLE 3 Precursor Component (Mix A) Wt % Portland Cement 36 Volcanic Ash (Scoria) 55 TiO2 4 FeCl2 5

The weight percentages of the chemical compounds in Mix A, which may vary from batch to batch by +/−15 wt %, are as follows:

TABLE 4 Precursor Compounds (Mix A) Wt % SiO2 24 Al2O3 6 Fe2O3 5 CaO 35 TiO2 4 FeCl2 16

Each of the samples marked as treated below used 2.5% by weight of precursor components based on the net weight of oil in the emulsion. In the case of the aqueous catalytic composition made with aqueous ferrous chloride as a starting material, the percent of ferrous chloride is based on the dry weight in the solution. All experiments were run at approximately 75° C. except Experiment 6, which was operated at 25° C. and Experiment 8, which was operated at 100° C.

Table 5 presents basic physical and chemical properties of the untreated oil, control samples and treated samples.

TABLE 5 Summary of Physical and Chemical Parameters Viscosity Vol. % Diluent Specific (cs) Added (Diluent Experiment Gravity API° at 7° C. Density: 0.7247) Pilot Control 1 - 1.0040 9.4 1,600,000 0 field test, Lab Control A- Treated 0.9505 17.3 3,000 19.7 Lab Control B- Treated 0.931 20.4 745 26.9 LabControl C- Treated 0.9142 23.2 270 32.9 LabControl D - Treated 0.8942 26.7 100 40.9 Field Experiment 3 - 0.9151 23.0 109 19.6 Treated Field Experiment 8 - 0.8679 31.5 25 21.4 Treated Field Experiment 5 - 0.9224 21.8 408 15.2 Treated Field Experiment 6 - 0.9054 24.7 283 4.6 2nd pass of Experiment 5

TABLE 6 Pilot Control 1 Experiment 3 Experiment 8 Untreated Oil Treated Oil Treated Oil Pour Point 15° C. — −51° C. Bromine Number 3.00 2.2 2.2  Total Acid Number 1.29 0.91 0.75 Total Sulfur (vol. %) 4.56 2.98 3.41 Pipeline Compliance N/A Passed Passed Test

Pilot Control 1 was a control experiment that did not include any of the catalytic composition. This run only involved water-oil emulsion and a relatively high level of diluent hydrocarbon, namely, 30 parts by volume of diluent hydrocarbon was added to 70 parts of oil (41.9% oil). From previous field experience it was known that addition of more than 30% diluent hydrocarbon is required to meet the viscosity requirements for pipeline transport. Nine m3 of emulsion and diluent hydrocarbon was processed in Pilot Control 1 with an emulsion temperature ranging from 65° C. to 80° C.

Pilot Control 1 provided a basis for subsequently studying the change in the composition of the gases in the top of the pressure tank. This pressure tank was used as a collection vessel for the treated or upgraded hydrocarbon fluid, water, gases, and solid precipitate from the various experiments. It was evacuated and cleaned after each run.

It was expected, based on the diluent hydrocarbon addition of 23.6% by weight or 30% by volume of a blended diluent hydrocarbon/oil barrel, that the release of C1 to C5 hydrocarbons as gas would be higher in Pilot Control 1 than subsequent experiments. Experiment 3 used 15% by weight of a blended oil/diluent hydrocarbon barrel and Experiment 8 had 16.4% by weight of a blended barrel of oil/diluent hydrocarbon.

Experiment 3 provided an initial insight into the potential level of effectiveness for cracking and hydrogenation by the aqueous catalytic composition in a pilot scale environment. The data in Table 5 and 6 show that significant and positive changes in the density, API, viscosity, and decrease in sulfur content, were achieved when compared with Pilot Control 1. In Experiment 3, 11.8 m3 of emulsion and diluent hydrocarbon were processed. The temperature of the Experiment 3 emulsion was 65° C. to 75° C. just before the addition of the aqueous catalytic composition and dropped after addition of the aqueous catalytic composition. The temperature increased by about 5° C. just before the mixture entered the settling tank. The resulting lower molecular weight hydrocarbon product had an API of about 23°.

This API value exceed the highest API value achieved at runs performed at ambient temperature (16° C. to 25° C.) with even two treatment passes with higher levels of diluent hydrocarbon. While the earlier laboratory results were evidence of a significant change, it was not as significant as the change that occurred in Experiment 3 with an emulsion temperature of 65° C. to 75° C. using only one treatment pass, 11.2% less diluent hydrocarbon and 43% less precursor component composition. The improved results can be explained from the increase in temperature as well as a modification to the formula for the aqueous catalytic composition.

Experiment 8 shows the outstanding result which can be achieved by the practice of the invention. The product from Experiment 8 had an API gravity of 31.5° and a viscosity of 25 cs at 7° C. 14.5 m3 of emulsion and diluent hydrocarbon were processed. The product also had a lower molecular weight with a lower bromine number (an indicator of the degree of unsaturation of the hydrocarbons) as compared to the untreated oil. The number dropped from 3 to 2. The total acid number dropped below 1.0 in Experiment 3 and 8. In Alberta, Canada, 1.0 is the threshold point where pipelines implement financial penalties for transporting the oil due to high acidity. Note also that the pour point dropped from +15° C. to −51° C. on the oil from Experiment 8. In this experiment, the emulsion temperature was approximately 100° C. just before the addition of the aqueous catalytic composition. The temperature of the treated emulsion stream leaving was approximately 75° C.

Experiments 6 is the treatment of the product of Experiment 5 using again the process of the invention. Between 13 m3 and 14 m3 of emulsion and diluent hydrocarbon were processed in Experiments 5 and 6. Experiment 5 was operated at about 65° C. to 75° C. emulsion input temperature prior to the addition of the aqueous catalytic composition. The emulsion temperature prior to the addition of the aqueous catalytic composition in Experiment 6 (the second pass) was about 18° C. to 25° C. Experiment 6 used relatively low amounts of diluent hydrocarbon, 3.4% by weight per barrel, and precursor component composition at 1.64% by weight to the net weight of oil in the emulsion. Based on laboratory measurements, the second pass made (Experiment 6) made a significant improvement in both density (0.9224 to 0.9254) and viscosity (API from 21.80 to 24.7°) This shows that further cracking and hydrogenation reaction can take place by treating the product which has been already treated using the process of the invention.

TABLE 7 Mass Boil-Off (%) by Temperature in Simulated Distillation Analyses 0- 0- 0- 0- 200- 250- 350- 450- 125° C. 150° C. 200° C. 350° C. 250° C. 350° C. 450° C. 525° C. Control 10.2 11.2 12.8 26 2.4 10.8 14 10 A Exp. 3 17 19 22 35 3 10.2 12.8 9 Change 66.7 69.6 71.9 34.6 25.0 −5.6 −8.6 −10.0 (%) Control 22 24.2 26.8 39.5 3 D Exp. 8 23.6 25 27.2 39.5 2.6 9.7 11.5 8 Change 7.27 0.03 0.01 0.00 −0.13 (%) Control 10.2 11.2 12.8 26 2.4 10.8 14 10 A Exp. 8 23.6 25 27.2 39.5 2.6 9.7 11.5 8 Change 131.4 123.2 112.5 51.9 8.3 −10.2 −17.9 −20.0 (%)

Control A has the same diluent hydrocarbon loading as for Experiment 3. The distillation profile for Control D most closely matches the distillation profile of Experiment 8, but it has a diluent hydrocarbon loading 2.55 times higher than for Experiment 8.

From Table 7 in the 0-125° C. range (Light Straight Run Naphtha) 66.7% by mass more of the lighter end hydrocarbon compounds have boiled off from Experiment 3 than from the Control A sample. In Experiment 8, 131.4% more light ends have boiled off than for the Control A sample. Experiment 8 has only 10% by mass more added diluent hydrocarbons than the Control A sample.

In the 0-200° C. range (Light and Heavy Straight Run Naphtha), Experiment 3 generated 71.9% more light ends than the Control A sample; Experiment 8 generated 112.5% more light hydrocarbons than did the Control A sample.

TABLE 8 Residual Fraction (Boiling points higher than 530° C.) Residual Fraction % Change from Untreated case Untreated Oil 0.67 Experiment 3 0.44 −34.6 Experiment 8 0.41 −5.5 Control A 0.50 20.8 Control B 0.47 −5.4 Control C 0.45 −4.9 Control D 0.40 −10.9

In Table 8, with respect to the reduction in the residual fraction (the compounds that boil above 530° C.), there is a reduction of 34.6% (14.5 gallons per barrel of crude oil) in the treated oil from Experiment 3 compared to the untreated oil.

TABLE 9 Percent Changes for Table 4A % Change from Control A to Experiment 3 = −12.4% % Change from Control A to Experiment 8 = −17.2% % Change from Control B to Experiment 8 = −12.5% % Change from Control C to Experiment 8 = −8.1%

The treated oil from Experiment 3 has 5.2 gallons per barrel less residual than that from the Control A experiment. There is a 16 gallons per barrel reduction in the residuals in Experiment 8 compared to the untreated oil. The treated oil from Experiment 8 is 7.2 gallons per barrel lower in residuals than that from the Control A experiment, and 5.3 gallons per barrel lower than that from the Control B experiment. Treated oil from Experiment 8 is even lower in residuals, 3.4 gallons per barrel, than that from the Control C control experiment which had almost double the initial loading of diluent hydrocarbon.

Table 10 compares the results of the SAPA (Saturates, Aromatics, Polars, and Asphaltenes) separation analyses of four samples of oil: the untreated oil, the outputs from Experiments 3 and 8, and Control A sample. The focus of the SAPA analysis is to examine the saturate, aromatic, polar (resin), and asphaltene fractions, as they exist above a 270° C. boiling point.

The aqueous catalytic composition (upgrading) technology applied in the pilot test changed an API 9.4° oil with a viscosity of 289,000 cs at 40° C. into an API 31.5° oil with a 25 cs at 7° C. These end-state changes are average values over the whole barrel of incoming crude not just the portion that boils below 350° C. to 530° C. which is considered in some conventional upgrading processes.

TABLE 10 Saturates, Aromatics, Polars and Asphaltenes (SAPA) Analyses-Changes in the Gas-Oil Range Mass % >270° C. Saturates Aromatics Polars Asphaltenes Loss of Light Ends Untreated Oil 24.2% 35.0% 24.2% 15.2% 1.4% Treated Oil - 18.0% 24.7% 17.7% 11.6% 28.0% Run 8 Change −25.6% −29.7% −26.9% −23.7% 1900.0% (Untreated to Experiment 8) Treated Oil - 17.6% 21.0% 24.6% 12.3% 24.6% Run 3 Change −27.3% −40.0% 1.7% −19.1% 1657.1% (Untreated to Exp 3) Control Sample 21.0% 25.6−% 26.5% 15.0% 11.9% A Change −13.2% −26.9% 9.5% −1.3% 750.0% (Untreated to Control A) Change (Exp. 3 2.3% 17.6% −28.0% −5.7% 13.8% to Exp. 8) Change (Control −16.2% −18.0% −7.2% −18.0% 106.70% A to Exp 3) Change (Control −14.3% −3.5% −33.2% −22.7% 135.3% A to Exp 8) SAPA measured in terms of sample mass percent of a barrel above a boiling point of 270° C. The five fractions of the SAPA test represents 100% of the barrel of oil. This test starts at a boiling point above 91% of the mass of the added diluent hydrocarbon.

This degree of change, along with the other factors listed above, has a significant impact on the value of the oil. This upgrading technology can be applied to the raw oil in a produced emulsion from the well or bitumen extraction plant with no chemical or other form of pre-treatment.

The compounds with boiling points below 270° C. are eliminated from analysis by the SAPA test and are listed as a fifth fraction, “Loss of Light Ends”. Insight into what constitutes the “Loss of Light Ends” fraction is given from Table 7.

Table 10 shows a consistent reduction in the heavier, higher boiling-point hydrocarbon compounds and the corresponding increase in lower molecular weight and lower boiling-point compounds by employing the process of the invention. Molecular and colloidal hydrocarbon structures in the saturates, aromatics, polars (resins), and asphaltene classes in the feed oil are broken down by cracking and hydrogenation mechanisms and appear in the treated oil as compounds that boil below 270° C. These lighter and lower boiling point compounds are moved into the fifth fraction of the SAPA analysis, “Loss of Light Ends”.

Comparing the properties of the treated oil from Experiment 8 with the untreated oil sample and the Control A sample, there is a significant reduction in the higher boiling point saturates (−25.6%), aromatics (−29.4%), polars (−26.9%), and asphaltene (−23.7%) fractions and a significant increase in the “Loss of Light Ends” fraction of 1900%. In comparing Experiment 8 with the Control A sample there is a change of −14.3% in saturates, −3.5% in aromatics, −33.2% in polars, and −22.7% in asphaltenes, and an increase of 135.3% in the Loss of Light Ends.

Table 8 shows the distribution and changes of the significant hydrocarbon compound structural fractions of the “Loss of Light Ends” segment from Table 5, SAPA. Specifically, the area of focus of the PNA test is in the 0° C. to 275° C. boiling point range.

TABLE 11 Changes in Concentrations of Paraffins, Naphthenes, and Aromatics (0 to 275° C. Boiling Range) Composition (% weight) Mono- Paraf- Naph- 1 2 Aro- aro- Alkyl- Naphtha- Diaro- Naphtha- fins thenes Ring Ring matics matics benzenes lenes matics lenes Control 56.70 32.60 26.40 6.20 10.70 10.10 8.50 1.60 0.70 0.70 A Exp 3 57.10 32.00 27.10 4.90 10.90 10.20 8.80 1.40 0.70 0.70 Exp 8 68.30 24.40 21.40 3.00 7.40 7.00 6.30 0.70 0.40 0.40 Changes in Comparison To Control A Sample Exp 3 0.7% −1.8% 2.7% −21.0% 1.9% 1.0% 3.5% −12.5% 0.0% 0.0% Exp 8 20.5% −25.2% −18.9% −51.6% −30.8% −30.7% −25.9% −56.3% −42.9% −42.9% Changes from Experiment 3 to Experiment 8 Change 19.6% −23.8% −21.0% −38.8% −32.1% −31.4% −28.4% −50.0% −42.9% −42.9% Exp 3 to 8

The PNA tests show that there is a chemical break-up (cracking and hydrogenation) of the heavier molecular compounds into lighter hydrocarbon compounds. In support of this, Experiment 8 shows significant reductions in naphthene content (−25.2%) and aromatic content (−30.8%) and an increase in the lower molecular-weight paraffin content (+20.5%) compared to the Control A sample.

The product from Experiment 3, as compared to the untreated oil, has a decreased content of six metals, an increase content of six other metals, and no change in the content of seven further metals. Significant decreases also occurred in the amounts of boron, molybdenum, silicon, sodium, and vanadium present in the output from Experiment 3; there was a significant increase in the amount of calcium present (90 ppm).

The treated oil from Experiment 8 also shows, in comparison to the untreated oil, a decrease in the content of six metals, an increase in the content of six other metals, and no change in the content of seven metals. Significant decreases occur in the amounts of boron, chromium, molybdenum, silicon, sodium, vanadium, and zinc in the output from Experiment 8. There was a significant increase in the calcium content (120 ppm) but this is not believe this negatively affects the oil's value at the refinery.

TABLE 12 Analyses of Gases (in ppm) in Headspace of Pressure Collection Tank Diluent Change Experi- HC Added from ment Vol % H2 CO2 Control % C1 C3 iC4 nC4 nC5 C6 C7 Control 30 1100 41,600 843,400 9,800 6500 29,000 17,300 1200 100 Exp 1 (65-75° C.) Exp. 3 19.6 1900 44,700 7.5 777,900 9,600 7900 39.500 40,500 6000 600 (65-75°) Exp. 8 21.4 0 2,700 −93.5 961,300 600 200 800 4,300 3900 1200 (100° C.) Exp. 5 15.2 0 2,900 −93.0 895,400 1,300 1000 6,000 32,400 12400 1700 (75° C.) Exp. 6 4.6 100 6,200 −85.1 888,000 3,400 2600 14,200 25,400 8200 2000 (20° C.)

Since the boiling point of C6 is 69° C. and of C7 is 98° C. and the temperature of the liquids and gases in the pressure tank were far below 69° C., the concentrations of C6 and C7 in the vapor phase is likely to be only a small fraction of their concentrations in the liquid phase. Similarly, the concentrations of these in the gas phase, as shown in Table 11, are quite low; however, there is a substantial concentration of gasoline range hydrocarbons in the liquid phase. The PNA test data, Table 10, and the simulated distillation data (not shown) further support an increase in light hydrocarbon liquid concentrations.

There is a 93.5% drop in the concentration of CO2 in the pressure tank headspace from the control experiment to Experiment 8. It is of interest to compare the composition of gases in particular experiments especially where the differences were significant as compared to the control experiment. In Pilot Control D, there is relatively high loading of diluent hydrocarbon. This generates a disproportionately high level of light-end hydrocarbons compared to the experiments where the products are treated in accordance with the invention. Also, the diluent hydrocarbon loading in the Control is near that necessary to reduce the viscosity of the heavy oil to a degree that it can be transported through a pipeline. The proportion of light molecular weight gases generated in Control Experiment 1 is abnormally high because of the relatively high diluent hydrocarbon addition compared in this case to the other experiments. This presents a significant threshold for the subsequent experiments to exceed in terms of showing real or significant chemical changes occurring as opposed to experimental measurement error or noise.

Control Experiment 1 involved 53% more diluent hydrocarbon by volume than did Experiment 3 but Experiment 3 resulted in 42% more hydrogen, about the same level of CO2, and approximately the same level of light hydrocarbon concentrations C1, and C3, as Experiment 1. But from C4 to C7. Experiment 3 had significant increases in compound concentrations over the control experiment. There is a 36% increase in n-C4, a 95% increase in i-C5, a 134% increase in n-C5, a 400% increase C6, and a 500% increase in the C7 concentration.

The concentrations measured in the product from Experiment 3 do not follow the trends of the subsequent experiments. One explanation for this is that the sample analyzed is not truly representative of the output from this experiment. However, the sample used to represent Experiment 3 gave good or consistent measurements in all other tests.

The treated oil from Control Experiment 1 has 40.2% by volume more diluent hydrocarbon than does that from Experiment 8 but the Experiment 8 oil has no detectable hydrogen, it shows a major drop in CO2 concentration of 93.5%, and a significant increase in C1 concentration of 14%. But from C3 to C5 the Experiment 8 output has significant decreases in compound concentrations compared to the output from the control. There is a 93.8% decrease in C3 concentration, a 97.2% decrease in n-C4, a 75% decrease in n-C5, an increase in C6 of 225%, and an 1100% increase in the C7 concentration.

There are significant differences between the headspace gas compound concentrations measured in the control experiment and the corresponding data from Experiments 8, 5, and 6. This implies a very active and positive effect of the aqueous catalytic composition. The is significant differences in distillation profiles between the treated samples from Experiment 3 and Experiment 8 and those of the various Control Samples (A, B, C) The differences are most pronounced with respect to Control samples A and B, particularly in the 0-150° C. range and the 0-250° C. range.

EXAMPLE 2

To further demonstrate the invention, pilot testing was performed in Lloydminster, Alberta, Canada. The oil from this region differs in composition from that used in the data reported above, i.e., from the SAGD Facility in Cold Lake.

The Lloydminster (Lloyd) pilot plant was designed on same basis and process concepts that was used at the Blackrock Cold Lake facility. Difference in the two facilities were that the Blackrock facility had a smaller capacity operation, the water/oil emulsion was already heated to 170° C., coming out of ground from a SAGD production operation, and at the Lloydminster plant the water/oil/CO2 emulsion was heated in a line-heater before was aqueous catalyst composition was blended into the emulsion stream at 95° C. to 115° C. At the Lloydminster facility, oil was trucked off and loaded into heated 1000 bbl storage tanks. The storage tanks were heated to 85° C. The approximate percent composition of the components of the catalyst precursors used it these experiments are as follows:

TABLE 13 Precursor Components Mix B (Wt %) Mix C (Wt %) Portland Cement 20 26 Volcanic Ash (Scoria) 71 79 TiO2 4 4 FeCl2 4 5

The weight percentages of the chemical compounds in Mix, which may vary from batch to batch by +/−15 wt %, are as follows:

TABLE 14 Precursor Compounds (Mix C) Wt % SiO2 39 Al2O3 12 Fe2O3 8 CaO 21 TiO2 5 FeCl2 5

The Lloydminster plant process system is a open system beginning at the treater or horizontal separator. Accordingly, any gases or vaporized light liquids with boiling points below the maximum horizontal separator temperature of 110° C. vaporized out of the system either to the off gas/liquid collection tank or to the atmosphere. These vapor losses definitely negatively affected the upgrading result with respect to density and viscosity of the treated oil. The “sales tanks,” at the end of the process stream, are also a point of vapor loss. The losses involve a range of light and middle range boiling point hydrocarbon compounds.

Table 15 below shows and untreated Lloydminster oil and three treated samples. The first two treated samples were treated with different catalyst. Both with the addition of CO2. Concentrate was added to Sample 7. The Sample 7B was prepared by taking the treated product of Sample 7, and adding 15 g of the condensate to 100 g of the Sample 7 product. Table 15 summarizes the sample preparation and the results obtained:

TABLE 15 Density, Viscosities, and Total Acid Numbers for Samples Viscosity Total Acid Density API 20° C. Number Untreated Lloyd Oil 0.9890 11.4 19,964 6.65 Mix C 1.8 wt % 2 scft/min 0.9499 17.5 824 CO2, No Condensate Added Sample 7, 2.3 wt % Mix B, 0.9556 16.5 1,449 2.45 4.5 scft/min CO2, 13 wt % condensate Sample 7B, 13 wt % 0.8960 26.3 77 0.65 condensate blended after initial treatment

The above data shows the substantive viscosity reduction achieved with the first two treated samples. The comparison between samples 7 and 7B shows the efficacy of a two stage treatment with the catalyst of the invention: there is substantial improvement in density, API, viscosity and total acid number.

The Table 16 below is SAPA analysis of untreated oil and the products of Samples 7 and 7B treated oils which boil above 260° C. The data show how the latter compositions differ from the untreated or raw oil. The saturate compounds increased 21% in Sample 7 and 29.9% in Sample 7B. This increase likely came from saturated aliphatic hydrocarbon fragments, probably cycloparaffins; from the heavy gas/oil fraction or from fragments from the cleavage of benzene rings from the aromatic fraction; or even from the residual fraction.

Aromatic compounds decreased by 10.8% in Sample 7 and 16.6% in Sample 7B. In order for there to be a decrease, the process of the invention must cleave the benzene ring.

TABLE 16 SAPA Analysis of Samples 7 and 7B Compared to the Untreated Lloyd Oil (270° C. and Above) % Loss of Sample Saturates Aromatics Polars Asphaltenes Light Ends Untreated Oil 14.7 35.0 42.9 7.4 7.8% Sample 7 17.8 31.2 43.4 7.6 15.6% Sample 7B 19.1 29.2 44.8 6.9 22% % Change from 21.0% −10.8% 1.1% 2.7% 100% Untreated to 7 % Change from 29.9% −16.6% 4.4% −6.8% 182% Untreated to 7B % Change 7.3% −6.4% 3.2% −9.2% 41% 7 to 7B

EXAMPLE 3

This examples compares four treated samples. Treated Sample 38 was treated with 2.4% of the Mix A catalyst (based dry wt. % of precursors to net weight of oil) at an emulsion temperature of 104° C. Sample 47 was treated with 1.7 wt % Mix A catalyst at an emulsion temperature of 104° C. In the treatment of both samples 38 and 47, 4.5 scft/min of CO2 was added to the emulsion. The “B” samples comprised the product of the treated Samples 47 and 38 mixed with 13% by weight of condensate. It will be noted from Table 17 below that post-treatment addition of condensate results in a dramatic difference in the end state density and viscosities in Sample 47B and 38B as compared to Samples 47 and 38.

TABLE 17 Density and Viscosity of Mix A Treated Oil Samples 38, 38B, and 47, 47B Sample Density API Viscosity at 20 C. 38 0.9826 12.4 31,479 38B (Sample 38 plus 13 wt % 0.9217 21.9 239 condensate) 47 0.9819 12.5 17,948 47B (Sample 47 plus 13 wt % 0.9189 22.4 193 condensate)

Condensate can also be added initially in the upgrading process as well as afterwards, if the chemical structure of the oil demands it. Even with the addition of condensate before and after treatment, the process of the invention uses considerably less condensate than that normally added to the Lloydminster area oil to make the viscosity acceptable for transport in intercontinental pipelines. Condensate addition to the Lloydminster oil for the purposes of pipeline transport can be in excess of 30%.

For Samples 38 and 47, data show a positive chemical change in the SAPA analyses after a single treatment pass through the plant. This pattern of change is similar to that shown for Sample 7. There is an increase in the saturates, a reduction in aromatics, and an increase in polar compounds, asphaltenes, and “Loss of Light Ends” fractions.

When condensate is added to the Samples 38 and 47, the pattern again is the same as for Sample 7, except for the asphaltenes fraction. There is an increase in the saturates, a reduction in aromatics, and increase in the “Loss of Light Ends.” In Samples 38B and 47B there is no change in the asphaltenes, while Sample 7B there is a 6.8% reduction. The post addition of condensate shows there is a disproportionate change in density and viscosity compared to what would be expected fro simple dilution. Most importantly, the samples “B” were stabilized and did not separate by density. The added condensate shows a significant solvent effect or bonding to stabilize the hydrocarbon complexes that make up the oil so that density and viscosity is homogenous throughout the volume of liquid. The condensate has a catalysis like effect that is effective after the Lloydminster oil has been treated by the process of the invention.

The PNA analysis of Samples 47, 47B, and 38B follow the pattern and direction of change seen in the PNA tests for Samples 7 and 7B. The PNA test covers the 0° C. to 270° C. With regard to the PNA data for Samples 38 and 47, the data show that aromatic compounds in the residual fractions go down significantly and that paraffins and naphthenes increase significantly.

EXAMPLE 4

This Example shows that by the use of the aqueous catalyst system of the invention, CO2 converts to organic compounds. To show this, 5.75 mols per hour of CO2 was injected into the emulsion flow system. It was observed that, in the 90 barrels of water recovered, there were 700 ppm in water phase. The equates to 313 mols of methanol. In an initial investigation, a mixture of water and oil containing a precipitate of a catalyst of the invention was collected from the separator of the pilot plant after the plant was shut down. The water phase was analyzed and found to contain 2,430 ppm of methanol and 5,275 ppm of isopropyl alcohol. It is believed, that in the practice of the invention for upgrading oil, such low boiling material would have the added effect of further reducing the viscosity of the upgraded oil.

Table 12 sets forth above shows an analysis of the product gases in the headspace of the pressure collection tank where the invention was practiced with the addition of carbon dioxide. In the control runs with just oil and condensate, 42,000 ppm of CO2 was found. Where the aqueous catalyst of the invention was added to the oil and condensate, there was a significant drop in CO2 concentration, an increase in methane and C6 and above hydrocarbons, and a reduction in the C2, C3 and C4 hydrocarbons. Based on these observations, it was concluded that methane and alcohols having two to four carbon atoms was formed. Of particular interest in connection with Table 9 is the marked reduction of carbon dioxide in Experiments 5 and 8.

All references, patents and patent applications cited and discussed in this specification are incorporated herein by reference in their entirety and to the same extent as if each was individually incorporated by reference.

Claims

1. A method of cracking a high molecular weight hydrocarbon to form a lower molecular weight hydrocarbon product, comprising:

(I) admixing (a) a high molecular weight hydrocarbon having an API value of less than about 12 and (b) an aqueous catalytic composition prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide;
(II) reacting the admixture from step (I) at a temperature from about 50° C. to about 200° C., thereby hydrogenating and cracking the high molecular weight hydrocarbon to form a lower molecular weight hydrocarbon product; said lower molecular weight product having an API value greater than the API value of the high molecular weight hydrocarbon composition.

2. The method of claim 1, wherein the aqueous catalytic composition is prepared by admixing and reacting, in an aqueous solution

i. about 15 to 40 weight percent cement,
ii. about 55 to 80 weight percent volcanic ash,
iii. about 2 to 8 weight percent titanium dioxide or boron oxide, and
iv. about 3 to 10 weight percent transition metal salt,
the weight percents being based on the total weight of components (i)-(iv).

3. The method of claim 2, wherein the volcanic ash component is one or more components selected from scoria, basalt, pyroclastic rock, tuff, tuffstone, volcanic glass, pumice, mafic rock, ultramafic rock, and silicate-based zeolites.

4. The method of claim 1, wherein step (I) comprises admixing (a) a high molecular weight hydrocarbon having an API value of less than about 12, (b) carbon dioxide, and (c) an aqueous catalytic composition prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide.

5. The method of claim 1, further comprising (III) stabilizing the lower molecular weight hydrocarbon product by admixing it with a diluent comprising a saturated hydrocarbon having from 5 to 25 carbon atoms.

6. The method of claim 4, further comprising (III) stabilizing the lower molecular weight hydrocarbon product by admixing it with a diluent comprising a saturated hydrocarbon having from 5 to 25 carbon atoms.

7. The method of claim 1, further comprising:

(III) recovering the lower molecular weight hydrocarbon from the product of step (II); and
(IV) admixing said lower molecular weight hydrocarbon from step (III) with a second aqueous catalytic composition thereby forming a hydrocarbon product having a molecular weight still lower than said lower molecular weight hydrocarbon product,
wherein the second aqueous catalytic compositions is prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide.

8. The method of claim 1, wherein the high molecular weight hydrocarbon is formed by diluting bitumens, asphaltenes, heavy oils, or tars.

9. The method of claim 7, wherein the high molecular weight hydrocarbon is formed by diluting the bitumens, asphaltenes, heavy oils, or tars with a C5 to C25 alkane or cycloalkane.

10. The method of claim 1, wherein the high molecular weight hydrocarbon is admixed with the aqueous catalytic composition at a weight ratio of from 2:1 to 4:1.

11. The method of claim 1, wherein the transition metal salt is ferrous chloride.

12. The method of claim 10, wherein the aqueous catalytic composition is formed from the following components:

i. about 25 to 50 weight percent silicon dioxide,
ii. about 6 to 20 weight percent aluminum oxide,
iii. about 5 to 15 weight percent ferric oxide,
iv. about 15 to 30 weight percent calcium oxide,
v. about 2 to 10 weight percent titania or boron oxide, and
vi. about 2 to 10 weight percent ferrous chloride,
the weight percents being based on the total weight of components (i)-(vi).

13. The method of claim 1, wherein the aqueous catalytic composition is formed from the following components:

i. about 15 to 40 weight percent cement,
ii. about 55 to 80 weight percent volcanic ash,
iii. about 2 to 8 weight percent titanium dioxide or boron oxide, and
iv. about 3 to 10 weight percent transition metal salt,
the weight percents being based on the total weight of components (i)-(iv).

14. A method of forming and stabilizing a lower molecular weight hydrocarbon prepared from the cracking and hydrogenating of a high molecular weight hydrocarbon, comprising:

admixing (a) a high molecular weight hydrocarbon having an API value of less than about 12, (b) carbon dioxide, and (c) an aqueous catalytic composition, said aqueous catalytic composition having been prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide; calcium oxide, and titania or boron oxide, thereby forming a stabilized lower molecular weight hydrocarbon product.

15. The method of claim 13, wherein the amount of carbon dioxide relative to the 1 bbl. of the high molecular weight hydrocarbon is from 5 to 50 scft.

16. The method of claim 13, further comprising admixing with the lower molecular lower molecular weight hydrocarbon a diluent comprising a saturated hydrocarbon having from 5 to 25 carbon atoms.

17. A method of reducing the concentration of carbon oxides in a gaseous or liquid medium comprising: passing said medium into an aqueous catalytic composition or an admixture of the aqueous catalytic composition and optionally a liquid hydrocarbon, at a temperature of at least 50° C. and pressure sufficient to react the carbon oxides; said aqueous catalytic composition being prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide.

18. A method of forming a lower molecular weight hydrocarbon from a high molecular weight hydrocarbon, comprising: wherein each of the first and second aqueous catalytic compositions is prepared by admixing and reacting, in an aqueous solution, a transition metal salt and particles of silicon dioxide, aluminum oxide, ferric oxide, calcium oxide, and titania or boron oxide, and the first and second aqueous catalytic compositions are the same or different.

(a) admixing a high molecular weight hydrocarbon having an API value of less than about 12 and a first aqueous catalytic composition thereby forming a lower molecular weight hydrocarbon product;
(b) recovering the lower molecular weight hydrocarbon from the product of step (a); and
(c) admixing said lower molecular weight hydrocarbon from step (b) with a second aqueous catalytic composition thereby forming a hydrocarbon product having a molecular weight still lower than said lower molecular weight hydrocarbon product,
Patent History
Publication number: 20080116111
Type: Application
Filed: Sep 18, 2007
Publication Date: May 22, 2008
Inventor: Jeffrey P. Newton (Ithaca, NY)
Application Number: 11/856,985
Classifications
Current U.S. Class: With Group Iv Metal Or Metal Oxide (i.e., Ti, Zr, Hf, Ge, Sn, Pb, Or Oxide Thereof) (208/111.1); Hydrogenative (208/107)
International Classification: C10G 47/04 (20060101); C10G 47/00 (20060101);