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Difference between revisions of "Inference liquid meters"

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[[Category:4.1.6 Compressors, engines, and turbines]]

Latest revision as of 18:44, 1 June 2015

Flowmeters are used to measure liquid/gas products.

Turbine liquid flowmeters

Turbine flowmeters are an effective means of accurate measurement of liquid/gas products in many industries. Because of the turbine meter’s versatility and flexibility in product metering applications, it is one of the most widely used technologies in flow measurement.

Turbine meters were invented in the 18th century by Reinhard Woltman, and at that time were used for water-flow measurement. In the 1950s, turbine meters were first used for hydrocarbon measurement for aeronautical applications within aircraft. In 1970, the API recognized the turbine meter in MPMS Chap. 5 Sec. 3, "Measurement of Liquid Hydrocarbons by Turbine Meters."[1] With these published standards, the turbine meter gained recognition as a custody-transfer metering technology acceptable for use in liquid-petroleum-products metering systems. These systems include crude-oil production and pipelines, petroleum product pipelines, refinery applications, tanker loading and unloading, crude-oil terminals, and refined-product loading-rack terminals. For additional information about turbine meters and their use in gas measurement, see Gas turbine meter.

Theory of operation of turbine meters

Turbine meters are inferential measurement devices. They infer the volumetric flow rate based on the mechanical properties of the meter and the physical properties of the measured fluid. Turbine meters are a combination of a mechanical assembly and electronic components to measure volumetric flow rates. See Fig. 1.

The turbine meter consists of a rotor with multiple blades mounted on a free-running bearing system. Fluid flow through the meter impinges on the turbine blades, causing the rotor to rotate on its axis along the centerline of the turbine-meter housing. The angular velocity to the turbine rotor is directly proportional to the fluid’s linear velocity through the meter housing. Given the fixed cross-sectional area of the meter housing and the linear velocity of the fluid through this area, the volumetric flow rate can be calculated.

A voltage pulse signal is produced as the rotor blade passes a magnetic pickup coil mounted externally on the meter housing. Each pulse represents a discrete volume of liquid. The number of pulses per unit volume is called the meter’s K-factor. The K-factor is determined during flow calibration and is unique to each and every meter. In smaller meter sizes, the unit of volume is typically given in gallons or liters. In larger meters, the unit of volume is typically given in barrels or cubic meters.

Coriolis liquid flowmeters

A meter utilizing the Coriolis force to measure mass flow rate was first patented in 1978. Most Coriolis meters can measure the density of the fluid in addition to the mass flow rate. Therefore, because volume flow rate is equal to mass flow rate divided by density, the associated electronics package can be programmed to output the volume flow rate. At this point, Coriolis meters become volume flow rate meters and can provide an output similar to such other meters as positive displacement and turbine meters. For additional information about Coriolis meters and their use in gas measurement, see Coriolis gas flowmeters.

Theory of operation of coriolis meters

The Coriolis force as first identified in 1835 refers to the deflection relative to the Earth’s surface of any object moving about the Earth. This force can also be produced on a vibrating tube(or multiple tubes). When a fluid moves through the vibrating tube, the Coriolis force causes the tube(s) to distort slightly. The degree of distortion is directly proportional to the mass flow rate of the fluid. Coriolis manufacturers use various proprietary techniques to monitor the magnitude of the distortion and process the measured signals into useable measurement information. As mass flow rate through the vibrating tube(s) increases, the offset in position or distortion monitored between the upstream and downstream portions of the tube(s) increases. See Fig. 2 for a typical Coriolis meter design. In addition to measuring the Coriolis force, most meters are capable of utilizing the frequency of vibration of the tube(s) to measure density.

Coriolis sensor considerations

Most manufacturers offer a comprehensive sizing program that provides information regarding accuracy, flow rate, pressure drop, and velocity with any given fluid and process condition.

Coriolis meters offer the advantage of a large turndown ratio—more than twice the turndown of a turbine meter. Flow velocity through a Coriolis meter is generally high. Velocity should always be considered when sizing a meter for an erosive fluid with high solids content and when considering piping limitations including pressure drop. The pressure drop across the meter should be known in order to select the proper size sensor. For example, a 4-in. meter can handle a rate of 2,500 bbl/hr but has a pressure drop at this rate of 13 psi (with a viscosity of 1 cp). Pressure drop should always be considered with any flowmeter that is operating near a fluid’s equilibrium vapor pressure so that the fluid does not cavitate or flash at the metering point. Air or gas slugs do not damage the meter; however, Coriolis meters are not intended to meter multiphase fluids.

Coriolis transmitter considerations

Coriolis meters are electronic. They require power and some associated device that interprets the signals from the meter and provides useable digital, analog, or serial outputs. Most meters today have a separate device or transmitter, but advances in technology have produced meters that produce an output directly from the sensor. Whether in a separate housing or located on the meter, there is a central processing unit (CPU) that is programmed to provide the output required. The CPU is programmed with the meter’s calibration coefficients and is programmed to output in the required units of measurement. Because there is no movement or mechanical action in the meter that can be utilized to produce a pulse, the CPU is also programmed to produce the pulse required for proving and for totalization.

Given the capabilities of electronics today, additional features such as alarm and control outputs, averaging, and calculation of relative density are easily a part of a Coriolis transmitter. Because the Coriolis meter is programmable, the means of configuring the meter should be understood in addition to the security of the device after installation in the field.

References

  1. Measurement of Liquid Hydrocarbons by Turbine Meters. 2000. In Manual of Petroleum Measurement Standards, fourth edition, CH. 5, Sec. 3. Washington, DC: API.

Noteworthy papers in OnePetro

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External links

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See also

Positive displacement liquid meters

Liquid meters

Liquid flow meter proving and LACT units

Gas meters

Coriolis gas flowmeters

Orifice gas meters

Ultrasonic gas meters

Gas turbine meter

PEH:Liquid_and_Gas_Measurement