Abstract: A method for fabricating calcite channels in a nanofluidic device is described. A photoresist layer is coated onto a top surface of a silicon nitride (SiN) substrate. After coating the photoresist layer, the photoresist layer is scanned with an electron beam in a predefined pattern. The scanned photoresist is developed to expose portions of the top surface of the SiN substrate in the predefined pattern. Calcite is deposited in the predefined pattern using atomic layer deposition (ALD) using a calcite precursor gas. Using a solvent, a remaining portion of the photoresist layer is removed to expose the deposited calcite in the predefined pattern and on the top surface of the SiN substrate, where a width of the deposited calcite is in range from 50 to 100 nanometers (nm).

Abstract: A method for fabricating calcite channels in a nanofluidic device is described. A photoresist layer is coated onto a top surface of a silicon nitride (SiN) substrate. After coating the photoresist layer, the photoresist layer is scanned with an electron beam in a predefined pattern. The scanned photoresist is developed to expose portions of the top surface of the SiN substrate in the predefined pattern. Calcite is deposited in the predefined pattern using atomic layer deposition (ALD) using a calcite precursor gas. Using a solvent, a remaining portion of the photoresist layer is removed to expose the deposited calcite in the predefined pattern and on the top surface of the SiN substrate, where a width of the deposited calcite is in range from 50 to 100 nanometers (nm).

Abstract: A method for fabricating calcite channels in a nanofluidic device is described. A porous membrane is attached to a substrate. Calcite is deposited in porous openings in the porous membrane attached to the substrate. A width of openings in the deposited calcite is in a range from 50 to 100 nanometers (nm). The porous membrane is etched to remove the porous membrane from the substrate to form a fabricated calcite channel structure. Each channel has a width in the range from 50 to 100 nm.

Abstract: Methods may include emplacing a downhole tool within a wellbore, sampling a fluid downhole with the downhole tool; analyzing the fluid, and calculating an interfacial tension (IFT), wherein calculating the acid-base IFT contribution comprises measuring a concentration of a surface-active species directly. Apparatuses for measuring an interfacial tension (IFT) in a fluid downhole may be part of a downhole tool and may include a sampling head to sample the fluid; and a downhole fluid analysis module that includes a spectrometer capable of measuring a concentration of a surface-active species in the fluid, and a processor configured to determine the IFT of the fluid downhole based on the measured concentration of the surface-active species.

Abstract: A downhole tool to make one or more downhole measurements of laser-induced vaporization and/or pyrolysis of hydrocarbons is provided and disposed at a desired location within a wellbore. A tool head of the downhole tool is brought into sealing engagement with the wellbore wall. The fluid within an interior region enclosed by the tool head and the wellbore wall is evacuated and a measurement spot is irradiated with a laser to generate volatile hydrocarbons and/or pyrolytic hydrocarbons. Measurements are made on the volatile hydrocarbons and/or pyrolytic hydrocarbons and one or more formation properties are inferred based on the measurements. A low level of laser radiation intensity, irradiating some or all of the wellbore wall enclosing the interior region, may be used to prevent measurement contamination, and both medium power and high power levels of laser radiation may be used to first vaporize and then pyrolyze the hydrocarbons.

Abstract: A method for fabricating calcite channels in a nanofluidic device is described. A photoresist layer is coated onto a top surface of a silicon nitride (SiN) substrate. After coating the photoresist layer, the photoresist layer is scanned with an electron beam in a predefined pattern. The scanned photoresist is developed to expose portions of the top surface of the SiN substrate in the predefined pattern. Calcite is deposited in the predefined pattern using atomic layer deposition (ALD) using a calcite precursor gas. Using a solvent, a remaining portion of the photoresist layer is removed to expose the deposited calcite in the predefined pattern and on the top surface of the SiN substrate, where a width of the deposited calcite is in range from 50 to 100 nanometers (nm).

Abstract: A composition for increased hydrocarbon production from a hydrocarbon-bearing reservoir. The composition includes a saltwater solution suitable for injection into the hydrocarbon-bearing reservoir for water flooding, the saltwater solution having a salinity; and a plurality of nanocapsules, where the nanocapsules are operable to be suspended amongst the saltwater solution, where the nanocapsules have an overall positively charged outer surface at respective outer shells of the nanocapsules, where the nanocapsules encapsulate water molecules within the nanocapsules, and where the nanocapsules are operable to release the water molecules in the hydrocarbon-bearing reservoir proximate overall negatively charged zones.

Abstract: A mineralogy composition of a formation of interest is determined using core samples or downhole measurements. A dry permittivity is determined for each identified mineral. A volumetric mixing law is employed using the determined mineralogy composition and the determined dry permitivities. An effective matrix permittivity is determined using results from the volumetric mixing law. Dielectric dispersion measurements of the subject formation are acquired using the core samples or the downhole measurements. A dielectric petrophysical model is produced using the dielectric dispersion measurements and the effective matrix permittivity. A water saturation is estimated based on the dielectric petrophysical model. Nuclear magnetic resonance (NMR) T2 measurements having short echo spacings are acquired. A NMR petrophysical model is generated based on the NMR T2 measurements. A total porosity is determined based on the generated NMR petrophysical model.

Abstract: A tool having a pump-out unit, pumping unit, and NMR unit is disposed in a wellbore. On a pump-up cycle, after removing borehole fluids, a fluid is injected into a region of investigation. NMR measurements are made while fluid migrates into the region of investigation. On a production cycle, pressure is removed, allowing fluid to exit the formation while NMR measurements are made. A rate of fluid production is estimated using the time-dependent NMR measurements. Alternatively, the mass of a sample is measured. Fluid is injected into the sample and the mass of the injected sample is measured. Pressure is removed and the mass of the injected sample as the fluid migrates out of the sample is measured. The change in mass of the injected sample as the fluid migrates out of the sample is determined and a rate of fluid production is estimated using the determined change in mass.

Abstract: A mineralogy composition of a formation of interest is determined using core samples or downhole measurements. A dry permittivity is determined for each identified mineral. A volumetric mixing law is employed using the determined mineralogy composition and the determined dry permitivities. An effective matrix permittivity is determined using results from the volumetric mixing law. Dielectric dispersion measurements of the subject formation are acquired using the core samples or the downhole measurements. A dielectric petrophysical model is produced using the dielectric dispersion measurements and the effective matrix permittivity. A water saturation is estimated based on the dielectric petrophysical model. Nuclear magnetic resonance (NMR) T2 measurements having short echo spacings are acquired. A NMR petrophysical model is generated based on the NMR T2 measurements. A total porosity is determined based on the generated NMR petrophysical model.

Abstract: Methods may include calculating a formation permeability for a subterranean formation from a combination of dielectric measurements and acoustic measurements, wherein the formation permeability is calculated according to the formula: kg=a(Vx? w/?r)b, where Vx is either Vp, Vs, or Vp/Vs, ? is formation conductivity, Øw is water-filled porosity, and a and b are constants that are empirically determined for the frequency selected with respect to Vx; and creating a design for a wellbore operation from the calculated formation permeability. Methods may also include obtaining a dielectric measurement from a downhole formation; obtaining an acoustic measurement from a downhole formation; and calculating a formation permeability from a combination of the dielectric measurement and the acoustic measurement.

Abstract: Sealing particles are used to stop or reduce undesired fluid loss. The sealing particles may be swellable or have effective cross-sectional areas greater than five square millimeters or are both swellable and have effective cross-sectional areas greater than five square millimeters. The sealing particles are disposed in one or more locations in which there is undesired fluid flow and, once lodged therein, stop or at least reduce the undesired fluid loss. A tubular having a bypass flow path may be used to deploy the sealing particles. The bypass flow path may use a biased or unbiased sleeve that is selectably movable to expose or block exit ports in the tubular. A retrievable sealing disk may be deployed to move the sleeve. The sealing particles may be made of a bi-stable material with extenders and may be actuated using swellable material. The sealing particles may extend in multiple dimensions.

Abstract: A NMR logging tool is provided and disposed in a wellbore at some desired depth. Packers are provided and actuated to hydraulically isolate a section of the wellbore and form a cavity between the NMR logging tool and the wall of the isolated section of the wellbore. The cavity is evacuated until a first desired pressure within the cavity is attained. Fluid is injected into the cavity until a second desired pressure within the cavity is attained. A plurality of NMR measurements is made on the region of the formation, each of the plurality of measurements being made at different times. Formation properties are inferred using the measurements. A baseline NMR measurement may be made when a first desired pressure is attained. A time-zero NMR measurement may be made when a second desired pressure is attained. Similar measurements may be made in a laboratory on a sample.

Abstract: The wettability of a formation may be estimated using a multi-frequency dielectric measurement tool. Multi-frequency dielectric dispersion measurements are made using the multi-frequency dielectric measurement tool on a sample. The bulk density and the total porosity of the sample are also otherwise acquired. The bulk density, matrix permittivity, total porosity, and multi-frequency dielectric dispersion measurements are input into a petrophysical dielectric model and the petrophysical dielectric model is applied to obtain inversion results. A wettability state of the sample is determined using the inversion results and one or more reservoir management decisions are made based on the determined wettability state of the sample. A non-transitory, computer-readable storage medium may be provided that has stored on it one or more programs that provide instructions.

Abstract: A mineralogy composition of a formation of interest is determined using core samples or downhole measurements. A dry permittivity is determined for each identified mineral. A volumetric mixing law is employed using the determined mineralogy composition and the determined dry permitivities. An effective matrix permittivity is determined using results from the volumetric mixing law. Dielectric dispersion measurements of the subject formation are acquired using the core samples or the downhole measurements. A dielectric petrophysical model is produced using the dielectric dispersion measurements and the effective matrix permittivity. A water saturation is estimated based on the dielectric petrophysical model. Nuclear magnetic resonance (NMR) T2 measurements having short echo spacings are acquired. A NMR petrophysical model is generated based on the NMR T2 measurements. A total porosity is determined based on the generated NMR petrophysical model.

Abstract: A measurement device makes measurements on a region of investigation in which a native fluid or complex fluid (e.g., emulsified fluid) has been replaced by a fluid of different viscosity. Various methods such as core flooding, pressure cycling, centrifuging, or imbibition may be used to replace the native fluid. The replacement fluid may include alkanes, alkenes, or some combination of those, and is preferably non-polar. The replacement fluid may mix with the native fluid within the pores to produce a mixture having a different viscosity than the native fluid. Measurements can be made on a sample in a lab or on an isolated region of a subsurface formation. Standard measurement techniques such as the Amott-Harvey technique or the United States Bureau of Mines technique may be used. Alternatively, NMR measurements may be performed. A parameter such as wettability and relaxivity is estimated using data obtained by the measurement device.

Abstract: For a given medium, a property may be inferred based on nuclear magnetic resonance (NMR) data. NMR data that includes two or more different NMR signals are used. Differences between any particular two of the two or more different NMR decays are computed and a distribution is produced based on the computed differences. The property of the medium may be inferred using the produced distribution. The produced distribution features the change in a parameter. The NMR distributions may be T2 distributions, T1 distributions, diffusion, or any other type of NMR data. The NMR data may be acquired: at different times, for different levels of invasion, before and after water flooding, or for different saturation states. The inferred property may pertain to the oil and gas industry, material analysis, medicine, pharmaceuticals, the process industry, or the food industry. For example, the inferred property may be the porosity of a subsurface formation.

Abstract: A permanent monitoring tool is provided and disposed in a wellbore. Measurements are made at different times using the permanent monitoring tool on a region of a formation penetrated by the wellbore. One or more properties of the formation are inferred at one or more depths of investigation within the region using the measurements. Any changes in the one or more inferred formation properties are determined and one or more reservoir management decisions are made based on the determined changes. The well may be an observation well, an injector well, or a production well. The permanent monitoring tool may be a magnetic resonance tool or an electromagnetic tool. The measurements may be stacked to improve the signal-to-noise ratio of the signal. Different depths of investigation may be selected using antenna arrays of different lengths. The inferred properties may be saturation or resistivity. Conductive or non-conductive casing may be used.

Abstract: A tool having an energy source and a surface roughness measurement device is provided. A baseline measurement of surface roughness of a sample is made. The sample is then exposed to energy from the energy source, causing the temperature of the sample to increase. A second measurement of surface roughness of the sample is made. The change in surface roughness of the sample is determined. Formation properties such as the total organic carbon in the sample is inferred based on the determined change in surface roughness of the sample. The tool may be disposed in a wellbore and may use packers to isolate a portion of the wellbore, or it may use a hydraulic seal on an extendible member to isolate a sample portion of the wellbore wall. The energy source may be a laser that produces radiation that selectively heats a particular component of the sample constituent material.

Abstract: A tool having two current electrodes, three or more voltage electrodes, and a measurement device capable of making electrical measurements is provided, along with a sample. With electrical connectivity to the sample, one current electrode is disposed at one location on the sample while the other current electrode is disposed at another location on the sample, and the three or more voltage electrodes are disposed on the sample intermediate the two current electrodes. An electric current is passed through the sample. The measurement device is used to make a first set of electrical measurements that involve a first pair of voltage electrodes and to make a second set of electrical measurements that involve a second pair of voltage electrodes. The first set of electrical measurements is compared to the second set of electrical measurements. It is inferred whether the sample has heterogeneous electrical properties using the compared electrical measurements.