Provided herein are improved methods for estimating the flow velocity of a fluid in a vessel. Systems and methods are provided herein related to making and/or refining velocity measurements for flowing fluids, both single and multi-phase fluids, in vessels, such as pipes or conduits, utilizing contrast media property agent variations. In one aspect, this disclosure provides a method of determining a flow velocity of a fluid flow in a vessel including: providing a fluid flow having contrast media, the contrast media having a contrast media property variation; providing a detectable signal corresponding to the contrast media property variation; collecting the detectable signal at an upstream receiver to produce a first received signal; collecting the detectable signal at a downstream receiver to produce a second received signal, the downstream receiver being located downstream of the upstream receiver at a distance (L); filtering the first received signal and the second received signal through a contrast media variant filter to produce a first filtered signal and a second filtered signal; cross-correlating the first filtered signal and the second filtered signal to determine a time shift (Δt) between the first filtered signal and the second filtered signal; and estimating the velocity of the fluid flow using this relationship vflow=L/Δt.

A ray transceiving system of an underwater flowmeter includes a flowmeter body. A fluid metering channel, a transmitting window, and a probing window are arranged on the flowmeter body. The transmitting window and the probing window are respectively in communication with the fluid metering channel, and each of the transmitting window and the probing window is provided with a titanium alloy isolation seat and a beryllium pad. Titanium alloy is used to seal the fluid metering channel, the titanium alloy and the beryllium pad are combined to bear pressure, and the beryllium pad is used to reduce absorption of gamma rays. A deduction metering method of the underwater flowmeter partially deducts the gamma count rate distortion caused by the Compton scattering effect, and calculates the content of each phase in a three-phase mixed flow to improve the metering accuracy of the three-phase content of oil, gas, and water.

A method for estimating a drilling fluid flow rate in a subterranean wellbore includes processing an acquired gamma ray spectrum in combination with standard elemental spectra and at least one standard oxygen activation spectrum to compute an oxygen activation yield. The oxygen activation yield is further processed to estimate a drilling fluid flow rate and or to infer a borehole diameter change or a lost circulation event. The gamma ray spectrum is acquired using a logging string employing a neutron source and a natural gamma ray sensor.

A device for measuring flow rate of wet gas based on an exempt radioactive source, includes a section of cylindrical pipe and a conical throttle located inside the cylindrical pipe and coaxially arranged therewith. The conical throttle includes a head cone section and a tail cone section arranged to have a common bottom surface. The head cone section faces a wet gas inlet of the cylindrical pipe. An annular gap is defined between the inner wall of the cylindrical pipe and the maximum diameter of the conical throttle for passage of wet gas. An exempt radioactive source block is arranged at the maximum diameter of the conical throttle in such a way that the gamma rays emitted from the radioactive source block can transmit radially through the annular gap to reach the gamma ray detector located outside the cylindrical pipe.

There is disclosed a method of assessing a flow of fluid in a borehole. The method comprises dispersing or mixing a tracer in the fluid of a borehole; and measuring a tracer concentration over a plurality of timepoints at a predetermined location in the borehole, wherein a decrease in the tracer concentration over time at said predetermined location indicates the borehole is in fluid communication with a flow of groundwater at or around said predetermined location.

Provided herein are improved methods for estimating the flow velocity of a fluid in a vessel. Systems and methods are provided herein related to making and/or refining velocity measurements for flowing fluids, both single and multi-phase fluids, in vessels, such as pipes or conduits, utilizing contrast media property agent variations. In one aspect, this disclosure provides a method of determining a flow velocity of a fluid flow in a vessel including: providing a fluid flow having contrast media, the contrast media having a contrast media property variation; providing a detectable signal corresponding to the contrast media property variation; collecting the detectable signal at an upstream receiver to produce a first received signal; collecting the detectable signal at a downstream receiver to produce a second received signal, the downstream receiver being located downstream of the upstream receiver at a distance (L); filtering the first received signal and the second received signal through a contrast media variant filter to produce a first filtered signal and a second filtered signal; cross-correlating the first filtered signal and the second filtered signal to determine a time shift (t) between the first filtered signal and the second filtered signal; and estimating the velocity of the fluid flow using this relationship vflow=L/t.

Provided herein are improved methods for estimating the flow velocity of a fluid in a vessel. Systems and methods are provided herein related to making and/or refining velocity measurements for flowing fluids, both single and multi-phase fluids, in vessels, such as pipes or conduits, utilizing contrast media property agent variations. In one aspect, this disclosure provides a method of determining a flow velocity of a fluid flow in a vessel including: providing a fluid flow having contrast media, the contrast media having a contrast media property variation; providing a detectable signal corresponding to the contrast media property variation; collecting the detectable signal at an upstream receiver to produce a first received signal; collecting the detectable signal at a downstream receiver to produce a second received signal, the downstream receiver being located downstream of the upstream receiver at a distance (L); filtering the first received signal and the second received signal through a contrast media variant filter to produce a first filtered signal and a second filtered signal; cross-correlating the first filtered signal and the second filtered signal to determine a time shift (t) between the first filtered signal and the second filtered signal; and estimating the velocity of the fluid flow using this relationship vflow=L/t.

A device for measuring flow rate of wet gas based on an exempt radioactive source, includes a section of cylindrical pipe and a conical throttle located inside the cylindrical pipe and coaxially arranged therewith. The conical throttle includes a head cone section and a tail cone section arranged to have a common bottom surface. The head cone section faces a wet gas inlet of the cylindrical pipe. An annular gap is defined between the inner wall of the cylindrical pipe and the maximum diameter of the conical throttle for passage of wet gas. An exempt radioactive source block is arranged at the maximum diameter of the conical throttle in such a way that the gamma rays emitted from the radioactive source block can transmit radially through the annular gap to reach the gamma ray detector located outside the cylindrical pipe.

A method to allocate single-phase fluid flow rate in a flowline system, the fluid flowing from multiple sources into a common collector. The method can include pulse injection of one or more tracers into the flowline system, and measurement of the tracer concentration downstream. The tracer concentration detection can be performed after the fluids from multiple sources commingle together. The mean transit time for each tracer can be calculated by applying the method of moments. The flow rate from each source can be further calculated by listing and solving all tracers' transport equations.

A first property, derivable from mass, of a drilling fluid is measured at a point upstream of a cuttings removal device. A second property (also derivable from mass) is measured at a point downstream of the cuttings removal device. A difference between the properties is determined over a period of time to obtain an estimate of the rate of cuttings removal. This allows the property of the drilling fluid before and after cuttings removal to be compared to give an indication of the rate of cuttings removal, which is indicative of the borehole cleaning.