The problem of how to accurately measure the flowrate of oil–gas–water mixtures in a pipeline remains one of the key challenges in the petroleum industry. This paper discusses why three-phase flow measurement is still important and why it remains a difficult problem to solve. The measurement strategies and principal base technologies currently used by commercial manufacturers are described, and research developments that could influence future flowmeter design are considered. Finally, future issues, which will need to be addressed by manufacturers and users of three-phase flowmeters, are discussed.

https://iopscience.iop.org/article/10.1088/0957-0233/24/1/012003/pdf

Three-phase flow measurement in the petroleum industry

At least one parameter of at least one fluid in a pipe (12) is measured using a spatial array of acoustic pressure sensors (14, 16, 18) placed at predetermined axial locations x1,x2,x3 along the pipe (12). The pressure sensors (14, 16, 18) provide acoustic pressure signals P1(t), P2(t), P3(t) on lines (20, 22, 24) which are provided to signal processing logic (60) which determines the speed of sound amix of the fluid (or mixture) in the pipe (12) using acoustic spatial array signal processing techniques with the direction of propagation of the acoustic signals along the longitudinal axis of the pipe (12). Numerous spatial array processing techniques may be employed to determined the speed of sound amix. The speed of sound amix is provided to logic (48) which calculates the percent composition of the mixture, e.g., water fraction, or any other parameter of the mixture or fluid which is related to the sound speed amix. The logic (60) may also determine the mach number (MX) of the fluid. The acoustic pressure signals P1(t), P2(t), P3(t) measured are lower frequency (and longer wavelength) signals than those used for ultrasonic flow meters, and thus is more tolerant to inhomogeneities in the flow. No external source is required and thus may operate using passive listening. The invention will work with arbitrary sensor spacing and with as few as two sensors if certain information is known about the acoustic properties of the system.

Fluid parameter measurement in pipes using acoustic pressures

https://www.repository.cam.ac.uk/bitstream/handle/1810/246007/Coriolis-draft-paper-V8.1-FMI-Larger-Fonts.pdf?sequence=1

Coriolis flowmeters: a review of developments over the past 20 years, and an assessment of the state of the art and likely future directions

The present invention is an apparatus for determining the flow rate of a fluid in a pipe. The apparatus includes a device for providing acoustic energy on a diagonal path through the fluid. The diagonal providing device is in contact with the pipe. The apparatus also includes a device for providing acoustic energy on a diametrical path through the fluid. The diametrical providing device is in contact with the pipe. The apparatus is also comprised of a device for determining the flow of fluid in the pipe based on the acoustic energy of the diagonal providing device and the acoustic energy of the diametrical providing device. In one embodiment, the diagonal providing device is fixedly disposed on the pipe. In another embodiment, the diametrical providing device provides acoustic energy emitted in both directions on the diametrical path. The diagonal providing device preferably includes a first transducer and a second transducer located at diametrically opposed positions about the pipe. The first transducer and second transducer are preferably adapted to alternatively function as transmitter and receiver so as to cause ultrasonic signals to travel through the fluid along the diametric path. The diametrical providing device preferably includes a third transducer and a fourth transducer located at diagonally opposed upstream and downstream positions relative to one another. The third transducer and the forth transducer are preferably adapted to alternatively function as a transmitter and receiver so as to cause ultrasonic signals to travel through the fluid alternatively in upstream and downstream directions along the diagonal path between the third transducer and the fourth transducer. The diametric path is adjacent to the diagonal path so that the transducers are sampling the same portion of fluid.

Apparatus for determining fluid flow

A multiphase flow meter distributed system is disclosed that is capable of measuring phase flow rates of a multiphase fluid. The distributed system includes at least one flow meter disposed along the pipe, an additional sensor disposed along the pipe spatially removed from the flow meter, and a multiphase flow model that receives flow related parameters from the flow meter and the additional sensor to calculate the phase flow rates. The flow meter provides parameters such as pressure, temperature, fluid sound speed and/or velocity of the fluid, and the additional sensor provides a parameter indicative of pressure and or temperature of the fluid. Depending on production needs and the reservoir dimensions, the distributed system may utilize a plurality of flow meters disposed at several locations along the pipe and may further include a plurality of additional sensors as well. The distributed system preferably uses fiber optic sensors with bragg gratings. This enables the system to have a high tolerance for long term exposure to harsh temperature environments and also provides the advantage of multiplexing the flow meters and/or sensors together.

Distributed sound speed measurements for multiphase flow measurement

Two-phase flow metering of heavy oil using a Coriolis mass flow meter: A case study

A method is disclosed for determining the composition of a two-phase fluid, such as saturated steam In that method, the transit times of sound are measured within the two-phase fluid, the speed of sound of the two-phase fluid is calculated from the measured transit times, and the composition of the two-phase fluid is calculated from the calculated speed of sound From the calculated linear velocity and the calculated composition, one can calculate at least one fluid property of the two-phase fluid, such as mass flow rate or energy flow rate All of these calculations can be performed by a microprocessor

Measurement of fluid properties of two-phase fluids using an ultrasonic meter

An automated method of determining relative permeability is described comprising the steps of injecting known flow rates of water and a hydrocarbon into a core; measuring a pressure differential across the core; flowing the water and the hydrocarbon into a water-hydrocarbon interface measuring column; monitoring an interface level in the column with an ultrasonic probe, and calculating relative permeability with an automated device based on the pressure differential and the interface level.

Automated steady state relative permeability measurement system

Wavy pipes were installed in the pipeline for mitigating severe slugging in pipeline/riser systems. Experimental results have revealed that: with a wavy pipe applied, the operating region of severe slugging is reduced; the severity of severe slugging and oscillation flow is mitigated; the wavy pipe performs better with its outlet located upstream of the riser base. The wavy pipe is essentially reducing the slug length. For severe slugging the wavy pipe works by accelerating the movement of the gas in the pipeline to the riser base; for the oscillation flow it works by mixing the gas/liquid two phases.

/pdf/experimental-study-on-severe-slugging-mitigation-by-applying-14s1duzjam.pdf

Joseph Shen

Papers

Two-phase flow metering of heavy oil using a Coriolis mass flow meter: A case study

Measurement of fluid properties of two-phase fluids using an ultrasonic meter

Automated steady state relative permeability measurement system

Experimental study on severe slugging mitigation by applying wavy pipes

A new flow conditioner for mitigating severe slugging in pipeline/riser system