A method for operating a Coriolis mass flowmeter includes: calculating error-free oscillation signal phase differences using a first measuring channel pair with a first measuring channel phase difference; calculating averaged error-containing oscillation signal phase differences using a second measuring channel pair with a second measuring channel phase difference; determining error-containing oscillation signal phase differences using a third measuring channel pair with negligible measuring channel phase difference; determining the second measuring channel phase difference by difference formation from the averaged error-containing oscillation signal phase differences of the second measuring channel pair and the error-free oscillation signal phase differences of the first measuring channel pair; obtaining error-free oscillation signal phase differences by subtracting the determined second measuring channel phase difference from the error-containing oscillation signal phase differences of the third measuring channel pair; and using the error-free oscillation signal phase differences for determining the mass flow rate.

In a method for quantifying a volumetric flow rate of a flow of drilling mud in a floating structure for subsoil drilling, a flowmeter and a detection device are provided on a floating structure for subsoil drilling. The flowmeter generates a flow signal. The detection device generates a heave signal representative of a vertical heave of the floating structure. A processor transforms the flow signal into a first spectrum in the frequency domain and the heave signal into a second spectrum in the frequency domain. The processor compares the first spectrum with the second spectrum, obtaining a resultant spectrum. The processor transforms the resultant spectrum into a resultant signal in the time domain. The processor determines a mean value of the flow signal, adds the resultant signal to the mean value, obtaining a quantification of a flow of drilling mud in the floating structure.

The method comprises producing a measurement signal (s1) having a signal parameter, followed with a temporal change (Δx1/Δt; Δx1′/Δt) of a primary measured variable (x1) and a temporal change (Δy1/Δt) of a disturbing variable (Δ1), and producing a measurement signal (s2) having a signal parameter, followed by a temporal change (Δx2/Δt; Δx2′/Δt) of a primary measured variable (x2). The method comprises ascertaining measured values (X.sub.I) of first type representing the primary measured variable (x1) or a secondary measured variable (f(x1) Δx1′) of measured values (X.sub.II) of second type representing the primary measured variable (x2) or a secondary measured variable (f(x2) Δx2′). The method comprises using measured values (X.sub.I) of first type and measured values (X.sub.II) of second type for ascertaining an error characterizing number (Err) representing a velocity error (ΔX.sub.I/ΔX.sub.II) caused by a change of the disturbing variable (y1).

The method comprises producing a measurement signal (s1) having a signal parameter, followed with a temporal change (Δx1/Δt; Δx1′/Δt) of a primary measured variable (x1) and a temporal change (Δy1/Δt) of a disturbing variable (Δ1), and producing a measurement signal (s2) having a signal parameter, followed by a temporal change (Δx2/Δt; Δx2′/Δt) of a primary measured variable (x2). The method comprises ascertaining measured values (X.sub.I) of first type representing the primary measured variable (x1) or a secondary measured variable (f(x1) Δx1′) of measured values (X.sub.II) of second type representing the primary measured variable (x2) or a secondary measured variable (f(x2) Δx2′). The method comprises using measured values (X.sub.I) of first type and measured values (X.sub.II) of second type for ascertaining an error characterizing number (Err) representing a velocity error (ΔX.sub.I/ΔX.sub.II) caused by a change of the disturbing variable (y1).

A method of determining vapor pressure of a fluid is provided. The method includes the steps of providing a meter (5) having meter electronics (20), the meter (5) being at least one of a flowmeter and a densitometer, and flowing a process fluid through the meter (5). A pressure of the process fluid is measured. The pressure of the process fluid is adjusted until a monophasic/biphasic boundary is reached. The flowing vapor pressure of the process fluid is determined at the monophasic/biphasic boundary.

Techniques for monitoring a well clean-up process are disclosed. In one embodiment, a method includes routing a multiphase fluid having oil and water to a separator of a well testing apparatus, separating the multiphase fluid into separate fluids via the separator, and routing the separated fluids away from the separator. The method also includes measuring flow rates of oil and water leaving the separator and determining individual flow rates of oil and water entering the separator as part of the multiphase fluid based on the measured flow rates of oil and water leaving the separator. Additional systems, methods, and devices are also disclosed.

Techniques for monitoring a well clean-up process are disclosed. In one embodiment, a method includes routing a multiphase fluid having oil and water to a separator of a well testing apparatus, separating the multiphase fluid into separate fluids via the separator, and routing the separated fluids away from the separator. The method also includes measuring flow rates of oil and water leaving the separator and determining individual flow rates of oil and water entering the separator as part of the multiphase fluid based on the measured flow rates of oil and water leaving the separator. Additional systems, methods, and devices are also disclosed.

The invention provides secure systems, methods and computer program products for monitoring fluid distribution within a fluid distribution network, and for validating received fluid distribution data, identifying unauthorized losses, and raising alerts in response to detection of unauthorized losses. The invention relies on a plurality of sensors disposed within the fluid distribution network, data received from said sensors, and validation and reconciliation of data based on a distributed ledger system, for detecting instances of unauthorized fluid loss.

The invention provides secure systems, methods and computer program products for monitoring fluid distribution within a fluid distribution network, and for validating received fluid distribution data, identifying unauthorized losses, and raising alerts in response to detection of unauthorized losses. The invention relies on a plurality of sensors disposed within the fluid distribution network, data received from said sensors, and validation and reconciliation of data based on a distributed ledger system, for detecting instances of unauthorized fluid loss.

A method for calibrating a flowmeter is provided that comprises determining a relationship between tube period ratio and a flow tube temperature compensation (FTC) value for a plurality of flowmeters. Tube periods of the flowmeter under test are measured. A stiffness-correlated FTC is calculated using the determined relationship between the tube period ratio and the FTC value for the plurality of flowmeters and the measured tube periods of the flowmeter under test. The stiffness-correlated FTC is applied to an operating routine (314) of the flowmeter under test.