Abstract: In some embodiments, the present disclosure pertains to methods of removing heteroatoms from a fluid by associating the fluid with one or more adsorbents, where the association results in the removal of the heteroatoms from the fluid. The association may occur by associating the fluid with a single adsorbent or a plurality of adsorbents in a sequential manner that maximizes heteroatom removal efficacy. The methods may be utilized to remove heteroatom-containing compounds from various fluids, such as fuels, hydrocarbons, alcohols, water, organic solvents, and combinations thereof. The one or more adsorbents may include, without limitation, activated carbon, zeolites, ion exchanged zeolites, ion impregnated zeolites, alumina, alumina nanowires, carbon-based supports, and combinations thereof. The methods of the present disclosure can be utilized to reduce heteroatoms in the fluid by more than about 50%, by more than about 80%, or by more than about 99%.

Abstract: Methods and systems of treating an oil shale formation using an in situ thermal process are described herein. A method of treating an oil shale formation in situ includes providing heat from one or more heat sources to at least a portion of the formation; allowing the heat to transfer from at least the portion to a selected section of the formation substantially by conduction of heat; pyrolyzing at least some hydrocarbons within the selected section of the formation; and producing a mixture from the formation.

Abstract: A hydrocarbon containing formation may be treated using an in situ thermal process. Hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to a first portion of the formation to mobilize hydrocarbons within the formation. Heat may be applied to a second portion of the formation to raise a temperature of the second portion to a pyrolysis temperature. Vaporized hydrocarbons and pyrolysis fluids may be produced from the formation.

Abstract: A coal formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. A formation may be selected that will produce a relatively large amount of condensable hydrocarbons and/or a relatively large amount of non-condensable hydrocarbons. Hydrocarbons within the formation may have a relatively high initial elemental hydrogen weight percentage. Hydrocarbons within the formation may have an initial hydrocarbon to carbon ratio within a desired range.

Abstract: A hydrocarbon containing formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. The formation to be treated may be selected based on initial moisture content of the formation.

Abstract: Wellbores may be formed in a hydrocarbon containing formation. Wellbores may be formed by geosteered drilling and/or by a steerable motor with an accelerometer. Parallel wellbores may be formed using magnetic steering. Heating mechanisms may be disposed within selected wellbores so that heat transfers to at least a portion of the formation during use. Selected wellbores may be production wells that allow for fluid removal from the formation.

Abstract: A hydrocarbon containing formation may be treated using an in situ thermal process. Hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. After production of the mixture is ended, the portion may be cooled to produce a spent portion of the formation.

Abstract: A coal formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation mixtures may be produced from the formation. The produced mixture may include non-condensable hydrocarbons having carbon numbers of less than 5. The weight percentage of non-condensable hydrocarbons with carbon numbers from 2 to 4 may be large as compared to methane weight percentage within the non-condensable hydrocarbons.

Abstract: A method for heat injection into a subterranean diatomite formation is provided. A heater is placed in a wellbore within the diatomite formation, and the heater is then operated at a temperature above that which the heater could be operated at long term in order to better sinter the formation in the vicinity of the wellbore. The improved sintering of the diatomite significantly improves the heat transfer coefficient of the diatomite and thereby increases the rate at which heat can be injected from a constant limited long term heater temperature.

Abstract: A method to cement a wellbore is provided wherein two fluids are transported into the wellbore through separate conduits, and combined within the volume to be cemented. The two fluids set to become a hardened cement after a short time period. The two fluids are preferably passed through a static mixer at the ends of the conduits within the wellbore to provide uniform contact between the two fluids. The two fluids are preferably a wellbore cement and an accelerator for that cement. Because the cement sets within a short time period, fluid loss from the wellbore is minimal. Additionally, the static head to which the formation is exposed is not excessive, even if a cement slurry having a density that exceeds the hydraulic fracture gradient of the formation is used.

Abstract: A mixture of propoxylated and ethoxylated surfactants is provided, along with a method to displace water flood residual oil from subterranean formations utilizing this mixture. The mixture is considerably less expensive than surfactants containing both propoxy and ethoxy groups, but provides the advantages of a graded lipophilic to hydrophilic structure of such surfactants.

Abstract: Drift or residual oil saturation within a reservoir around a wellbore is determined by injection of a water-soluble tracer and then producing from the well. This injection is performed twice. The first injection is immediately followed by production in order to create a baseline. The second injection is followed by a soak period, and then production. Production of the tracers is compared to determine drift or residual oil saturation within the reservoir.

Abstract: A method is provided for troubleshooting gas-lift wells, to identify whether gas-lift valves on the production tubing are open or closed, without the use of wireline tools. The method may also be used to detect leaks in the production tubing or in the well casing. A quantity of a tracer gas is injected into the lift-gas at the wellhead, and its return in fluid produced from the well is monitored as a function of time. The tracer's return pattern may be correlated with the depth of entry points and volumes of lift-gas entering along the length of the production tubing.

Abstract: A method is provided for troubleshooting gas-lift wells, to identify whether gas-lift valves on the production tubing are open or closed, without the use of wireline tools. The method may also be used to detect leaks in the production tubing or in the well casing. A quantity of a tracer gas is injected into the lift-gas at the wellhead, and its return in fluid produced from the well is monitored as a function of time. The tracer's return pattern may be correlated with the depth of entry points and volumes of lift-gas entering along the length of the production tubing.

Abstract: A method is provided for troubleshooting gas-lift wells, to identify whether gas-lift valves on the production tubing are open or closed, without the use of wireline tools. The method may also be used to detect leaks in the production tubing or in the well casing. A quantity of a tracer gas is injected into the lift-gas at the wellhead, and its return in fluid produced from the well is monitored as a function of time. The tracer's return pattern may be correlated with the depth of entry points and volumes of lift-gas, entering along the length of the production tubing.

Abstract: Methods are provided for determining mechanical and petrophysical properties (density, porosity, bulk compressibility, Young's modulus, Poisson's Ratio) of a material undergoing mechanical deformation studies with an imaging (CT, NMR) apparatus. The methods may also be used to measure and depict any fractures in the material.

Abstract: Apparatus is provided for performing mechanical deformation studies of a sample of material to determine mechanical and petrophysical properties of such a sample. The apparatus is useful in conjunction with an imaging (NMR or CAT) apparatus.

Abstract: Sample holder apparatus for use in imaging (X-ray CT/NMR) apparatus is provided. The sample holder may be employed to conduct fluid flow studies on a sample and to measure petrophysical properties of a sample. The sample holder may consist of non-ferromagnetic, nonmetallic components; these components are: an outer tubular member containing end plugs that are restrained from outward movement by end member assemblies (which may be metallic) that releasably engage an engagement means, or raised shoulder, on the outer member, and an interior assembly, containing a sample, which is contained in the outer tubular member.

Abstract: Residual oil saturation is determined by injecting an aqueous solution containing a carbonate salt, an acid-generating material and a radioactive material which are each selectively water soluble, displacing the solution with an aqueous solution devoid of the reactants and tracer, and, after CO.sub.2 has formed within the reservoir, producing aqueous fluid from the reservoir and utilizing radioactive analysis to measure the chromatographic separation between the radioactive material and the CO.sub.2.

Abstract: Residual oil saturation is determined by injecting water containing CO.sub.2, a base-generating material and at least one radioactively labeled material which is or becomes a selectively water-soluble tracer material mixed with the injected CO.sub.2, so that the arrival of the oil and water-partitioning tracer material is demarked by a decrease in CO.sub.2 concentration and the arrival of at least one of tracer material detected by a radioactivity analysis.