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Research Papers: Multiphase Flows

# Mass Fraction Measurements in Controlled Oil-Water Flows Using Noninvasive Ultrasonic Sensors

[+] Author and Article Information
Anirban Chaudhuri

Scientist
Los Alamos National Laboratory,
Los Alamos, NM 87545
e-mail: anirban@lanl.gov

Dipen N. Sinha

Scientist and LANL Fellow
Los Alamos National Laboratory,
Los Alamos, NM 87545
e-mail: sinha@lanl.gov

Abhijit Zalte

McDougall School of Petroleum Engineering,
Tulsa, OK 74104
e-mail: abhijit-zalte@utulsa.edu

Eduardo Pereyra

Research Associate
McDougall School of Petroleum Engineering,
Tulsa, OK 74104
e-mail: eduardo-pereyra@utulsa.edu

Charles Webb

Bakersfield, CA 93311
e-mail: charles.webb@chevron.com

Manuel E. Gonzalez

Global Alliance Manager
Chevron ETC,
Houston, TX 77002
e-mail: gonzame@chevron.com

From definition, if $φ$ is the volume fraction of oil in the two-phase mixture and $ρ$ is the composite mixture density, then

$ρ=ρoφ+ρw(1-φ)$

where $ρo$ and $ρw$ are the respective densities of the pure crude oil and pure water. If $mo$ is the mass of pure crude oil and $m$ is the total mass of the mixture, then we can also write

$ρ=mmo/ρo+(m-mo)/ρw=1φm/ρo+(1-φm)/ρw$

where $φm=mo/m$ is the mass fraction of oil. These two expressions for $ρ$ can be combined to get the expression for $φm$ in Eq. (9).

1Corresponding author.

Contributed by the Fluids Engineering Division of ASME for publication in the JOURNAL OF FLUIDS ENGINEERING. Manuscript received March 8, 2013; final manuscript received November 13, 2013; published online January 27, 2014. Assoc. Editor: Mark R. Duignan.

J. Fluids Eng 136(3), 031304 (Jan 27, 2014) (8 pages) Paper No: FE-13-1141; doi: 10.1115/1.4026055 History: Received March 08, 2013; Revised November 13, 2013

## Abstract

Controlled flow rate tests using mixtures of crude oil and water at different mass fractions were carried out in a flow loop at the University of Tulsa. A noninvasive acoustic method developed at the Los Alamos National Laboratory (LANL) was applied to calculate the mass and volume fractions of oil and water in the mixed two-phase flow by measuring the speed of sound through the composite fluid mixture along with the instantaneous temperature. The densities and sound speeds in each fluid component were obtained in advance for calibration at various temperatures, and the fitting coefficients were used in the final algorithm. In this paper, we present composition measurement results using the acoustic technique from LANL for different mixture ratios of crude oil and water and at varying flow rates and a comparison of the results from the acoustics-based method with those from Coriolis meters that measured individual mass flow rates prior to mixing. The mean difference between the two metering techniques was observed to be less than 1.4% by weight and is dependent on the total flow rates. A Monte Carlo analysis of the error due to calibration uncertainty has also been included.

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## Figures

Fig. 1

Flow loop schematic. Symbols ρ, m, T, and WC stand for measured density, mass flow rate, temperature, and water-cut, respectively, while subscripts W and MO stand for water and mixed oil, respectively. The water line has a single Coriolis meter, while the oil line has a Coriolis meter and a Drexelbrook probe.

Fig. 2

Oil and water holding tanks and pump layout at the TUFFP flow loop

Fig. 3

Differences in flow profiles in the absence and presence of a dynamic mixer

Fig. 4

Sound speeds and densities measured in the single phase crude oil (subscript o) and water (subscript w) samples as a function of temperature

Fig. 5

Comparison of calculated water-cuts by weight from upstream Coriolis meters (1 – φloopcorr) and LANL meter (1 – φm) in typical test runs

Fig. 6

Measured fluid temperatures during typical test runs

Fig. 7

Measurement error due to undertainties in independent variables

Fig. 8

Distribution of Monte Carlo trial runs for three different water-cut scenarios

## Errata

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