Last Updated 30 Mar 2019

Ultrasonic flowmeters in custody transfer and fiscal measurements of natural gas

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As oil and gas flow from numerous wells owned by different firms are merged into one flow line, it is usually necessary to meter the production from the firms separately before it enters the common processing facility (flow line). Actors in this field have to measure the raw materials (crude oil/natural gas) and the finished products (PMS, DPK, etc.) accurately, for the reason that they pay for what comes in and get paid for what goes out and any tiny deviation in their measurements could cost them a huge sums of money per annum.

The concept of custody transfer as defined by Dupuis and Hwang (2010) is the transfer of ownership of fluids from one party to another. It is the point at which ownership changes hands for the products being measured. On the other hand fiscal (custody transfer) measurements are the basis for money transfer, either between company and government or between two companies (NFOGM, 2005). In general, custody transfer involves industry standards, National Metrology standards, contractual agreements between parties involved and government regulations and taxation.

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The flow meters are the measurement instruments used to determine the quantity of flow within the system and various forms of it are used in custody transfer applications among which are ultrasonic meters, coriolis meters, turbine meters, positive displacement meters etc. This piece of exercise will look into some works on ultrasonic and flow meters which is among the most common flow meters in application.


Ultrasonic metering technology could be broadly classified into three viz- transit time, Doppler and cross correlation technology. In his work on multipath ultrasonic flow meters for gas measurement, Farestvedt (2003) states that ultrasonic technology uses sound at higher frequencies than what the human ear can hear (> 20 kHz). Most natural gas Ultrasonic meters (USM’s) use frequencies around 100-200 kHz, while liquid USM’s are in the 1 GHz range. Multipath USM’s utilize a minimum of three pairs of transducers; with primary application being fiscal and custody transfer metering of gas and liquid. Lansing (2008) opined that the use of USM’s for fiscal applications has grown substantially over the past several years due in part to its accuracy (<0.1%), large turndown (typically >50.1), non-intrusiveness, low maintenance cost, fault tolerant capabilities and integral diagnostics i.e. data for ascertaining the condition of the meter is accessible. Drenthen and de Boer (2010) in their research work attributed the aforesaid successes of the ultrasonic technology to the manufacturing methods and procedures that result in tight tolerances in the geometry of the meter. While the accuracy of the meter is largely a function of the quality of the geometry and accuracy of the time measurement, the stated performance of the meter can be guaranteed based on a dry calibration only. Therefore, they went further to determine the influence of the manufacturing tolerances on the uncertainty of the measurement, in which their findings have shown that the geometry and dimension of the meter body and the Reynolds (profile correction) factor are the significant sources of uncertainty. A dry calibration procedure performed yields a reproducibility of 0.3% which corresponds to the uncertainty, thus, with high quality fabrication and advanced calibration methods a USM of high fidelity could be achieved.

Calibration of an ultrasonic flow meter for natural gas measurement is conducted under the prevailing atmosphere at the flow calibration facility. Most of the systems use natural gas flowing in a pipeline; therefore it is usually impossible to alter parameters such as temperature, pressure and gas composition, each of which has an effect on the speed of sound. Freund et al (2002) investigated whether or not the calibration is still valid if those parameters are modified. They conducted a number of carefully controlled calibrations to measure the effect of changes in these parameters on the calibration of the USM’s initially calibrating a 200mm (8 inch) and two 300 mm (12 inch) ultrasonic meters in the High Pressure Loop at Southwest Research Institute (SwRI) utilizing natural gas at 2.8 MPa (400 psi) which was then changed to nitrogen, providing a 16% change in the speed of sound, equivalent to a natural gas pressure of 4.6 MPa (667 psi). Further test were done at different pressures using nitrogen. Their findings showed that the change in the speed of sound over the pressure range was within 0.03% of the calculated value. Moreover the test was performed at different temperatures for both the nitrogen and natural gas and calibrations were performed. It was realised that the ultrasonic meters was insensitive to change in speed of sound, temperature and pressure. Hence, they concluded that the calibration of an ultrasonic meter at one set of conditions does not affect its accuracy when it’s been utilized under another, including using different gases. However accumulation of contamination in the pipeline conveying the gas affects the accuracy of the meter as corroborated by Gorman (2006) and Zanker and Brown (2000), it reduces the internal diameter, shorten the transient time and hence a higher velocity reading and changes in the velocity profile due to surface roughness, but with regular maintenance of the pipeline, this anomaly could be avoided.

In several years, ultrasonic meters have become one of the fastest growing new technologies in the natural gas arena and having established that the USM’s could perform well under different operating conditions, it is paramount to look further to see how it functions in the measurement of gas for custody transfer purposes. When using a USM for custody transfer of natural gas, the following factors should be considered for effective fiscal metering to be achieved. The Meter tube alignment to and away from the ultrasonic sensor must be aligned perfectly. American Gas Association Article 9 allows the tube-to-meter match to be within 1.0%. Noise emanating from control valves can interfere with an ultrasonic sensor’s measurement, so a good practice is to place valves downstream of meters (if possible), put as much distance as possible between valves and meters, and put some bends in the piping to reduce noise. “Noise trap” tees are very effective in reducing valve noise. Temperature sensors location of is critical for maximum accuracy. For gas, AGA 9 recommends the thermowell be installed between two and five diameters downstream of the flowmeter in a uni-directional system, and three diameters from the meter in a bidirectional installation. One flowmeter is designated as the flow prover. This is a flowmeter of exceptional accuracy, and one that has been calibrated and tested recently and lastly a flow computer which performs the industry-standards flow calculations and serves as the cash register of the entire system (Dupuis and Hwang).

In conclusion, it could be seen from the analysis of the various researches and writings on ultrasonic flow meters that despite the fact that it has a very high accuracy level typically less than 0.1% (Drenthen and de Boer, 2010) and can operate under different conditions, its performance could be affected by the accumulation of contaminants in the pipeline conveying the natural gas.


Dupuis, E., Hwang, G., Custody Transfer: Flowmeter as a Cash Register, Control Engineering [online] Available at[tt_news]=39535 [Accessed 11 April 2011]

Norwegian Society for Oil and Gas Measurements, 2005, handbook of Multiphase Flow meterinng.[pdf].2nd ed. Stocholm. Available at [Accessed 11 April 2011]

Drenthen, J.G., de Boer, G., (2001), The manufacturing of ultrasonic flow meters, Flow Measurement and Instrumentation 12(2001), pp. 89-99

Freund et al., (2002), North Sea Flow measurement Workshop, Operation of Ultrasonic Flow Meters at Conditions Different Than Their Calibration, [pdf] Available at [Accessed 10 April 2011]

Gorman, J., (2006), Contaminant Accumulation Effect on Gas Ultrasonic Flow Meters International School of Hydrocarbon Measurement Class #1340 [pdf] Available at [Accessed 10 April 2011]

Zanker, J. k., Brown, G.J., (2000), North Sea Flow measurement Workshop, The Performance of a Multi-Path Ultrasonic Meter With Wet Gas [pdf] Available at[Accessed 10 April 2011]

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