666 results about "Fluid property" patented technology

Methods and apparatus for downhole analysis of formation fluids by isolating the fluids from the formation and/or borehole in a pressure and volume control unit that is integrated with a flowline of a fluid analysis module and determining fluid characteristics of the isolated fluids. Parameters of interest may be derived for formation fluids in a static state and undesirable formation fluids may be drained and replaced with formation fluids that are suitable for downhole characterization or surface sample extraction. Isolated formation fluids may be circulated in a loop of the flowline for phase behavior characterization. Real-time analysis of the fluids may be performed at or near downhole conditions.

The present invention relates to a method and apparatus for measuring a property relating to fluid flow in an earth formation, more specifically to directly measuring formation permeability and other fluid characteristics. The present invention provides a method for determining the permeability of a hydrocarbon bearing earth formation, which method comprises the steps of: locating a tool at a selected position in a borehole penetrating the earth formation; inducing a flow of fluid within the earth formation to said tool; creating at least two MRI images of said fluid while flowing within the earth formation to said tool, said at least two images being created at different times; determining displacement of said fluid within the earth formation between said different times, using the at least two MRI images.

Described herein are methods for optimizing petroleum reservoir analysis and sampling using a real-time component wherein heterogeneities in fluid properties exist. The methods can help predict the recovery performance of oil such as, for example, heavy oil, which can be adversely impacted by fluid property gradients present in the reservoir.

A system to measure fluid flow characteristics in a pipeline, meter, and methods includes a pipeline having a passageway to transport flowing fluid therethrough, a process density meter including at least portions thereof positioned within the pipeline to provide flowing fluid characteristics including volumetric flow rate, fluid density, and mass flow rate of the flowing fluid, and a fluid characteristic display to display the fluid characteristics. The process density meter includes a vortex-shedding body positioned within the pipeline to form vortices and a vortex meter having a vortex frequency sensor to measure the frequency of the vortices and to determine the volumetric flow rate. The process density meter further includes a differential pressure meter positioned adjacent the vortex-shedding body to produce a differential pressure meter flow rate signal indicative of the density of fluid when flowing through the pipeline. The process density meter also includes a thermal flow meter positioned adjacent the vortex-shedding body to produce a mass flow rate signal indicative of the mass flow rate of fluid when flowing through the pipeline. The process density meter produces an output of a volumetric flow rate, a flowing fluid density, and a mass flow rate to be displayed by the fluid characteristic display.

A method for determining properties of a formation fluid including obtaining data related to an optical density at a methane peak and an optical density at an oil peak for a fluid sample at a plurality of times, calculating an apparent gas-oil-ratio of the sample fluid from the optical density of the fluid sample at the methane peak to the optical density of the fluid sample at the oil peak at each of the plurality of times based on the data, selecting a power function of a sampling parameter for a buildup of the apparent gas-oil-ratio, calculating an exponential constant of the power function based on the data, and determining at least one selected from the group consisting of a contamination free gas-oil-ratio and a percent contamination.

Methods and systems are provided for downhole analysis of formation fluids by deriving fluid properties and associated uncertainty in the predicted fluid properties based on downhole data, and generating answer products of interest based on differences in the fluid properties. Measured data are used to compute levels of contamination in downhole fluids using an oil-base mud contamination monitoring (OCM) algorithm. Fluid properties are predicted for the fluids and uncertainties in predicted fluid properties are derived. A statistical framework is provided for comparing the fluids to generate, in real-time, robust answer products relating to the formation fluids and reservoirs thereof. Systematic errors in measured data are reduced or eliminated by preferred sampling procedures.

A method for determining a formation fluid property includes acquiring a suite of nuclear magnetic resonance (NMR) measurements of a fluid sample using a pulse sequence that includes pulsed field gradient pulses for encoding diffusion information, wherein each NMR measurement in the suite is acquired with a different value in a parameter in the pulsed field gradient pulses for producing a different diffusion effect, wherein the acquiring is performed in a formation fluid sampling tool in a borehole; inverting the suite of NMR measurements to produce a distribution function that relates diffusion properties of the fluid sample with an NMR property of the fluid sample; and determining the formation fluid property from the distribution function.

A device and method for sensing fluid characteristics, including, temperature, pH and chemistry, comprises a switch affixed to or embedded in a container of a size, shape and density such that said container floats stable in said liquid sensors which measure and report other characteristics of the liquid, such as temperature, pH, viscosity, chemistry or biochemistry.

A measurement device is provided that determines fluid properties from vibration frequencies of a sample cavity. In one embodiment, the measurement device includes a sample flow tube, vibration source and detector mounted on the tube, and a measurement module. The sample flow tube receives a flow of sample fluid for characterization. The measurement module employs the vibration sources to generate vibrations in the tube. The measurement module combines the signals from the vibration detector on the tube to determine properties of the sample fluid, such as density, viscosity, compressibility, water fraction, and bubble size. The measurement module may further detect certain flow patterns such as slug flow, for example. To measure the sample fluid density, the measurement module determines the resonant frequency of the sample flow tube. The density can then be calculated according to a formula that compensates for the temperature and pressure of the system.

An apparatus and methods for acoustically analyzing a fluid sample and determining one or more properties of the sample are disclosed by the present invention. The apparatus comprises a chamber, a transmitter positioned within the chamber for transmitting an acoustic signal through the fluid, a reflector movably positioned within the fluid inside the chamber for reflecting the acoustic signal, and a receiver positioned within the chamber for detecting reflections of the acoustic signal. The methods employ the use of a transmitter, a reflector movably positioned within the fluid inside the chamber, and a receiver to characterize the fluid sample based on one or more of its acoustic properties.

A system, method, and fluid analysis module are provided for the real-time analysis of multiphase fluids. The system generally comprises means for directing a fluid stream from a flow line to a fluid analysis module, a processor and communication means. The fluid analysis module comprises sensor for measurement of at least one property of the fluid. The processor processes the measurement data from the sensor, and the communication means communicates the processed data to a central acquisition unit or computer.

Apparatus and methods are described for autonomously controlling fluid flow in a tubular in a wellbore. A fluid is flowed through an inlet passageway into a biasing mechanism. A fluid flow distribution is established across the biasing mechanism. The fluid flow distribution is altered in response to a change in the fluid characteristic over time. In response, fluid flow through a downstream sticky switch assembly is altered, thereby altering fluid flow patterns in a downstream vortex assembly. The method “selects” based on a fluid characteristic, such as viscosity, density, velocity, flow rate, etc. The biasing mechanism can take various forms such as a widening passageway, contour elements along the biasing mechanism, or a curved section of the biasing mechanism passageway. The biasing mechanism can include hollows formed in the passageway wall, obstructions extending from the passageway wall, fluid diodes, Tesla fluid diodes, a chicane, or abrupt changes in passageway cross-section.

This invention disclosed herein provides methods, devices, software products, and systems for infusing a fluid into a blood vessel is provided that includes the step of administering the fluid into the blood vessel in programmed pulses. The programmed pulses generally defined by programmed pulse variables that include a fluid flow rate, a frequency, and a duration. Values of the programmed pulse variables may be determined based at least in part on a fluid property of the fluid to be infused that is relevant to streaming, blood flow in the blood vessel to be infused, a catheter size, or a patient profile.

The invention provides a device for controlling the composition and/or volume of a fluid within a reservoir. The device includes a reservoir adapted to contain at least one fluid, a means for monitoring a characteristic of the fluid contained in the reservoir, and a means for introducing additional fluid into the reservoir according to the fluid characteristic monitored by the monitoring means. The device also includes an acoustic generator for generating acoustic radiation. A dispensing means may be provided as well. Other devices and methods that use acoustic radiation to control the composition and/or volume of a fluid within a reservoir are included.

A drilling fluid, spacer fluid and cementing compositions for use in subterranean wells are disclosed along with methods for making using same, where the compositions include a weighting system having an effective amount of a metal silicon alloy, mixtures of metal silicon alloys, or mixtures of metal silicon alloys and conventional weighting agents, to produce compositions having a desired high density, while retaining other fluid properties such as pumpability, gas tight sealing, low tendency to segregate, and reduced high temperature cement strength retrogression.

A device for determining a location of an interface between a first fluid and second fluid includes a non-mechanical sensor that measures a selected parameter of interest relating to the fluid surrounding the sensor (“the surrounding fluid”) and a processor for processing the sensor measurements. The non-mechanical sensor measures a parameter relating to the surround fluid without physically co-acting with the surrounding fluid. Exemplary parameters such as thermal properties, electrical properties, fluid properties, and magnetic properties can be measured. The processor is programmed to process the sensor measurements to identify one or more characteristics in the measurements that can indicate the nature of the fluid being measured and thereby determine the location of the interface. The determined location can be used to operate a downhole device such as a pump, to provide real-time monitoring of well conditions, to record data for long-term reservoir characterization, or to actuate an alarm.