441 results about "Fluid density" patented technology

A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation ensures that the conductivity of water inflow below the productive zone of the subterranean formation is reduced. The method consists of two principal steps. In the first step, a fracture in and below the productive zone of the formation is initiated by introducing into the subterranean formation a fluid, free of a proppant, such as salt water, fresh water, brine, liquid hydrocarbon, and/or nitrogen or other gases. The proppant-free fluid may further be weighted. In the second step, a proppant laden slurry is introduced into the subterranean formation which contains a relatively lightweight density proppant. Either the fluid density of the proppant-free fluid is greater than the fluid density of the proppant laden slurry or the viscosity of the proppant-free fluid is greater than the viscosity of the proppant laden slurry. The method limits undesirable fracture height growth in the hydrocarbon-bearing subterranean formation during the fracturing.

A fluid delivery system capable of delivering a precise amount of fluid and monitor certain properties of the fluid so that the correct fluid is safely delivered to its intended destination. The system makes use of a flow sensor comprising a freestanding tube portion vibrated at a resonant frequency, wherein the resonant frequency corresponds to the density of the fluid flowing through the tube portion and the tube portion exhibits a degree of twist that varies with the mass flow rate of the fluid flowing therethrough. Movement of the tube portion is then sensed to produce a first output signal corresponding to the fluid density and a second output signal corresponding to the mass flow rate. The system is also equipped to measure elapsed time and to stop fluid flow in response to either of the first and second output signals.

For conveying a fluid, the measuring transducer is equipped with a measuring tube, which is held oscillatably in a support element and vibrates during operation. The measuring tube executes, during operation, at least over part of its length, driven by an exciter arrangement, bending oscillations about an oscillation axis. These bending oscillations predominantly assume an oscillation form having at least three bending oscillation antinodes. Inlet-end and outlet-end oscillations are registered by means of a sensor arrangement. Additionally provided in the measuring transducer is a coupler arrangement connected with measuring tube and with support element and having at least one coupling element interacting mechanically, especially resiliently, with the vibrating measuring tube and the support element. By suitable choice of the effective spring constant, c₆₀, of the coupler arrangement, this can cancel transverse forces produced, during operation, on the part of the vibrating measuring tube, for example due to fluctuating fluid density.

The present invention provides a sample tank having a window for introduction of electromagnetic energy into the sample tank for analyzing a formation fluid sample down hole or at the surface without disturbing the sample. Near infrared, mid infrared and visible light analysis is performed on the sample to provide a downhole in situ or surface on site analysis of sample properties and contamination level. The onsite analysis comprises determination of gas oil ratio, API gravity and various other parameters which can be estimated by a trained neural network or chemometric equation. A flexural mechanical resonator is also provided to measure fluid density and viscosity from which additional parameters can be estimated by a trained neural network or chemometric equation. The sample tank is pressurized to obviate adverse pressure drop or other effects of diverting a small sample.

Noninvasive method for determining the liquid level and density inside of a container having arbitrary dimension and shape. By generating a flexural acoustic wave in the container shell and measuring the phase difference of the detected flexural wave from that of the originally generated wave a small distance from the generated wave, while moving the generation and detection means through the liquid/vapor interface, this interface can be detected. Both the wave generation and wave detection may be achieved by transducers on the surface of the container. A change in the phase difference over the outer surface of the vessel signifies that a liquid/vapor interface has been crossed, while the magnitude of the phase difference can be related to fluid density immediately opposite the measurement position on the surface of the vessel.

The present invention provides drilling systems for drilling subsea wellbores. The drilling system includes a tubing that passes through a sea bottom wellhead and carries a drill bit. A drilling fluid system continuously supplies drilling fluid into the tubing, which discharges at the drill bit bottom and returns to the wellhead through an annulus between the tubing and the wellbore carrying the drill cuttings. A fluid return line extending from the wellhead equipment to the drilling vessel transports the returning fluid to the surface. In a riserless arrangement, the return fluid line is separate and spaced apart from the tubing. In a system using a riser, the return fluid line may be the riser or a separate line carried by the riser. The tubing may be coiled tubing with a drilling motor in the bottom hole assembly driving the drill bit. A suction pump coupled to the annulus is used to control the bottom hole pressure during drilling operations, making it possible to use heavier drilling muds and drill to greater depths than would be possible without the suction pump. An optional delivery system continuously injects a flowable material, whose fluid density is less than the density of the drilling fluid, into the returning fluid at one or more suitable locations the rate of such lighter material can be controlled to provide supplementary regulation of the pressure. Various pressure, temperature, flow rate and kick sensors included in the drilling system provide signals to a controller that controls the suction pump, the surface mud pump, a number of flow control devices, and the optional delivery system.

A computer-based system generates digital and audio responses to changes in fluid and rock properties of a producing hydrocarbon reservoir for surveillance analysis. The system calibrates observed changes against directly-measured field data in order to optimize the reservoir model. The changes may include, for example, stress changes in rock, impedance changes in rock, and fluid density changes.

System and methods are disclosed for fluid measurements which may be utilized to determine mass flow rates such as instantaneous mass flow of a fluid stream. In a preferred embodiment, the present invention may be utilized to compare an input mass flow to an output mass flow of a drilling fluid circulation stream. In one embodiment, a fluid flow rate is determined by utilizing a microwave detector in combination with an acoustic sensor. The acoustic signal is utilized to eliminate 2 pi phase ambiguities in a reflected microwave signal. In another embodiment, a fluid flow rate may be determined by detecting a phase shift of an acoustic signal across two different predetermined transmission paths. A fluid density may be determined by detecting a calibrated phase shift of an acoustic signal through the fluid. In another embodiment, a second acoustic signal may be transmitted through the fluid to define a particular 2pi phase range which defines the phase shift. The present invention may comprise multiple transmitters/receivers operating at different frequencies to measure instantaneous fuel levels of cryogenic fuels within containers positioned in zero or near zero gravity environments. In one embodiment, a moveable flexible collar of transmitter/receivers may be utilized to determine inhomogenuities within solid rocket fuel tubes.

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 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.

Subsurface wellbore conditions are measured directly in the wellbore while the fluid circulation system is not pumping. The measured values are recorded at the subsurface location and subsequently transmitted to the well surface when circulation is resumed using fluid pulse telemetry (FPT). Real-time measurements made when the fluids are circulating are transmitted real time using FPT. Axially spaced measurements are used to obtain differential values. The apparatus of the invention comprises an assembly carried by a drill string that is used to selectively isolate the area within the well that is to be evaluated. The apparatus includes an assembly having axially spaced inflatable well packers that are used to isolate an uncased section of the wellbore. The apparatus is equipped with self-contained measuring and recording equipment, a fluid receiving reservoir, circulation valving, measurement while drilling equipment, and automated controls. Measurements are made while the circulation is terminated or while the well packers are being used to isolate an area of the wellbore from the circulating fluid. The method is used to directly measure and evaluate conditions caused by pumping and drill string movement, such as swab and surge pressures. Other conditions such as the formation strength, formation pressure, the fluid density, and other subsurface conditions related to the well are also measured.

A method of determining the acoustic impedance of a fluid in a borehole, by gating a reflected acoustic signal into a plurality of time slots, and comparing received energies of the signal for the time slots to obtain a value indicative of the acoustic impedance of the fluid. The value may be normalized to yield the acoustic impedance of the fluid using the acoustic impedance of, e.g., water as a calibration point. The comparison is performed by comparing a ratio of an integration of a first ring down time slot and a second ring down time slot, to an integration of an internal reflection time slot. The acoustic pulse may be generated using a transducer immersed in an intermediate fluid contained within a chamber defined in part by a plate in contact with the borehole fluid and having a thickness such that a mechanical resonance frequency of the plate in a thickness mode is substantially equal to a resonance frequency of the transducer. The sonic velocity of the fluid is also measured and, when combined with the acoustic impedance, is used to determine the fluid density.

The invention relates in a one aspect to a method or apparatus for measuring flow properties of a multiphase fluid stream flowing in a pipeline comprising means for sampling, with a sampling probe, a portion of the fluid stream; for measuring a differential pressure between a first pressure of the fluid stream in the pipeline and a second pressure of the portion of the fluid stream in the sampling probe; for controlling flow rate of the sampled portion, wherein the flow rate of the sampled portion is controlled to provide for nullification of the differential pressure in order to obtain substantially isokinetic sampling of the fluid stream; for measuring properties of the portion of the fluid stream; and for processing the measured properties to determine the flow properties of the multiphase fluid stream flowing in the pipeline, wherein the above elements do not require- or are performed without the determination of the density of fluid in the fluid stream through nuclear radiation methods.

The invention discloses a marine riser vibration characteristic simulation test device under a deepwater well drilling working condition. The marine riser vibration characteristic simulation test device comprises a pool (1) and a trailer (2), wherein a lifting device A (3) is arranged on a horizontal sliding rail (8) of the trailer (2), a marine riser model (5) is connected with a connector A (9) at the bottom of the lifting device A (3) and a connector B (10) at the bottom of a lifting device B (4), the connector A (9) is communicated with a container (6), the connector B (10) is communicated with a liquid pump (7), and a tension adjusting device (33) is further arranged on the marine riser model (5). The invention further discloses a test method of the device. The marine riser vibration characteristic simulation test device has the advantages of being capable of simulating vibration performance of a marine riser of deepwater well drilling under different working conditions, suitable for marine riser models with different lengths, capable of simulating influence of different types of tensile force, different well drilling fluid density, different drilling fluid viscosity, different well drilling discharge capacity and different well drilling rotating speeds on vibration characteristics of the marine riser models, and capable of accurately obtaining real-time data in the test process.

Micromachine fluidic apparatus incorporates a free-standing tube section and electrodes to actuate or control the movement of the tube section, or to sense the movement of the tube section, or both. Electronic circuitry, which may be disposed on the same substrate as the fluidic portion of the apparatus, is used in conjunction with the tube and electrodes in conjunction with a variety of different applications, including fluid flow measurement, fluid density measurement, fluid viscosity measurement, fluid transport, separation and/or mixing. According to a particular embodiment, the free-standing section of the tube is resonated for fluid flow and density measurements according to the Coriolis effect. Capacitive/electrostatic actuation techniques are used to control or resonate the free-standing section of the tube, and to detect variations in tube movement. Different methods of fabricating micromachine fluidic apparatus are also disclosed, including the use of fusion bonding of non-conducting substrates, high-aspect ratio etching techniques, and anisotropic etching and refill techniques, preferably utilizing chevron-shaped slit openings to fabricate microtube sections.

Methods and apparatus for measuring density of a fluid. The apparatus includes a shaft adapted to be positioned within a fluid and a biased float disposed on the shaft and capable of movement along the shaft. The apparatus further includes a displacement sensor for detecting a position of the float along the shaft. A method of sensing the density includes positioning the biased float in the fluid and sensing the position of the float to obtain data representative of the density of the fluid.

A method for determining the composition of fluids flowing through pipes from noninvasive measurements of acoustic properties of the fluid is described. The method includes exciting a first transducer located on the external surface of the pipe through which the fluid under investigation is flowing, to generate an ultrasound chirp signal, as opposed to conventional pulses. The chirp signal is received by a second transducer disposed on the external surface of the pipe opposing the location of the first transducer, from which the transit time through the fluid is determined and the sound speed of the ultrasound in the fluid is calculated. The composition of a fluid is calculated from the sound speed therein. The fluid density may also be derived from measurements of sound attenuation. Several signal processing approaches are described for extracting the transit time information from the data with the effects of the pipe wall having been subtracted.

The present invention provides a chemometric equation to estimate fluid density, viscosity, dielectric constant and resistivity for a formation fluid sample downhole. The chemometric estimates can be used directly as estimated values for fluid density, viscosity, dielectric constant and resistivity for a formation fluid sample downhole. The chemometric estimates can also be plugged into a Levenberg-Marquardt (LM) non-linear least squares fit, as an initial estimate of the parameter to be estimated by the LM fit. If the initial parameter estimate is too far from the actual parameter values, the LM algorithm may take a long time to converge or even fail to converge entirely. The present invention estimates an initial value of a parameter that provides a high probability that the LM algorithm will converge to a global minimum.