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Corrosion in deadlegs occurs as a result of water separation due to the very low flow velocity. The present work aims to investigate the effect of geometry on flow field oil/water separation in deadlegs in an attempt for obtaining the conditions for avoiding formation of deadleg.

The investigation is based on the solution of the mass and momentum conservation equations of an oil/water mixture together with the volume fraction equation for the secondary phase. A fluid flow model based on the time‐averaged governing equation of 3D turbulent flow has been developed. An algebraic slip mixture model for the calculation of the two immiscible fluids (water and crude oil) is utilized.

Results are obtained for different lengths of the deadleg. The inlet flow velocity is kept unchanged (1.0 m/s) and the deadleg length to diamter ratio (L/D_B) ranges from 1 to 7. The considered fluid mixture contains 90 percent oil and 10 percent water (by volume). The results show that the size of the stagnant fluid region increases with the increase of L/D_B 1≈3D_B.

Deadlegs should be avoided whenever possible in design of piping for fluids containing or likely to contain corrosive substance. When deadlegs are unavoidable, the length of the inactive pipe must be as short as possible to avoid stagnant or low‐velocity flows.

The model solves the continuity and momentum equations for the mixture, and the volume fraction equation for the secondary phase utilizing an algebraic expression for the relative velocity.

The purpose of this paper is to present an implementation of ultrasonic tomography simulation to investigate the laminar flow of stratified liquid between water and oil.

The velocity of ultrasonic waves varies in water, oil, and different composition of water and oil. The composition of water and oil can be determined from the measurement of this propagation time. Sixteen pairs of ultrasonic sensors are mounted non‐invasively around the periphery of an acrylic pipe. The grease is used as the coupling material to mount these ultrasonic sensors. Different compositions of water and oil are used and the propagation times of the ultrasonic waves through the medium are measured. The composition of the water and oil of the flow is determined from the reconstructed images.

The paper finds that information about the distribution of the components within the sensing zone is obtained from the sensors' measurements. These measurements are then used to reconstruct the cross‐sectional image which can be analyzed to provide information, such as concentration of the flow components, the flow condition, velocity, mass flow rate, and identification of the distribution of mixing zones in stirred reactors and interface measurement in complex separation processes. The image can also be analyzed quantitatively for subsequent use to improve process control or develop models to describe individual process.

The paper shows that industries which may benefit from this technique could be the raw material processing industry, large‐scale and intermediate chemical production, and food biotechnology.

The purpose of this paper is to compute the pressure drop through sudden expansions and contractions for two‐phase flow of oil/water emulsions.

Two‐phase computational fluid dynamics (CFD) calculations, using Eulerian–Eulerian model, are employed to calculate the velocity profiles and pressure drops across sudden expansions and contractions. The pressure losses are determined by extrapolating the computed pressure profiles upstream and downstream of the expansion/contraction. The oil concentration is varied over a wide range of 0‐97.3 percent by volume. The flow field is assumed to be axisymmetric and solved in two dimensions. The two‐dimensional equations of mass, momentum, volume fraction and turbulent quantities along with the boundary conditions have been integrated over a control volume and the subsequent equations have been discretized over the control volume using a finite volume technique to yield algebraic equations which are solved in an iterative manner for each time step. The realizable per phase k‐ ε turbulent model is considered to update the fluid viscosity with iterations and capture the individual turbulence in both the phases.

The contraction and expansion loss coefficients are obtained from the pressure loss and velocity data for different concentrations of oil–water emulsions. The loss coefficients for the emulsions are found to be independent of the concentration and type of emulsions. The numerical results are validated against experimental data from the literature and are found to be in good agreement.

The present computation could not use the surface tension forces and the energy equation due to huge computing time requirement.

The present computation could compute realistically the two‐phase pressure drop through sudden expansions and contractions by using a two‐phase Eulerian model and hence this model can be effectively used for industrial applications where two‐phase flow comes into picture.

The original contribution of the paper is in the use of the state‐of‐the‐art Eulerian two‐phase flow model to predict the velocity profile and pressure drop through industrial piping systems.

The purpose of this paper is to study a multiphase-flow instrumentation for film thickness measurement, especially impedance-based, not only for gas–liquid flow but also for mixtures of immiscible and more viscous substances such as oil and water. Conductance and capacitive planar sensors were compared to select the most suitable option for oil – water dispersed flow.

A study of techniques for measurement of film thickness in oil – water pipe flow is presented. In the first part, some measurement techniques used for the investigation of multiphase flows are described, with their advantages and disadvantages. Next, examinations of conductive and capacitive techniques with planar sensors are presented.

Film thickness measurement techniques for oil–water flow are scanty in the literature. Some techniques have been used in studies of annular flow (gas–liquid and liquid–liquid flows), but applications in other flow patterns were not encountered. The methods based on conductive or capacitive measurements and planar sensor are promising solutions for measuring time-averaged film thicknesses in oil–water flows. A capacitive system may be more appropriate for oil–water flows.

This paper provides a review of film thickness measurements in pipes. There are many reviews on gas – liquid flow measurement but not many about liquid – liquid flow.

The purpose of this paper was to investigate the corrosion behaviour of API X65 pipeline steel in the simulated CO₂/oil/water emulsion using weight loss technique, potentiodynamic polarization technique and characterization of the corroded surface techniques.

The weight loss analysis, electrochemical study and surface investigation were carried out on API X65 pipeline steel that had been immersed in the CO₂/oil/water corrosive medium to understand the corrosion behaviour of gathering pipeline steel. The weight loss tests were carried out in a 3L autoclave, and effects of temperature, CO₂ partial pressure, water cut and flow velocity on the CO₂ corrosion rate of API X65 pipeline steel were studied. Electrochemical studies were carried out in a three-electrode electrochemical cell with the test temperature was 60°C, and the CO₂ partial pressure was 1 atm by recording open circuit potential/time and potentiodynamic polarization characteristics. The surface and cross-sectional morphologies of corrosion product scales were characterized using scanning electron microscopy. The phases of corrosion product scales were investigated using X-ray diffraction.

The results showed that water cut was the main controlling factor of API X65 steel corrosion under the conditions of CO₂/oil/water multiphase flow, and it had significant impact on corrosion morphology. In the case of higher water cut or pure water phase, general corrosion occurred on the steel surface. While water cut was below 70 per cent, corrosion morphology transformed into localized corrosion, crude oil decreased corrosion rate significantly and played a role of inhibitor. Crude oil hindered the corrosion scales from being dissolved by corrosive medium and changed dimension and accumulation pattern of the crystal grain, thickness and structure of the corrosion scales; thus, it influenced the corrosion rate. The primary corrosion product of API X65 steel was ferrous carbonate, which could act as a protective film at low water cut so that the corrosion rate can be reduced.

The results can be helpful in selecting the suitable corrosion inhibitors and targeted anti-corrosion measures for CO₂/oil/water corrosive environment.

The purpose of this paper is to study planar sensor geometries for the measurement of film thickness in a viscous oil–water flow. The study is relevant due to there are only a few measurement techniques for oil-water flow and these techniques involve oil with low viscosity (close to the water viscosity). Specifically, some techniques have been used in the studies of annular flow (gas–liquid and liquid–liquid flows), but applications in other flow patterns were not encountered.

Different sensor geometries were numerically simulated to compare their characteristics and choose the best to measure the water film thickness in the oil–water flow through an impedance-based technique. Finite element method was used for resolving the tridimensional electric field over each sensor. The compared characteristics were the penetration depth, the sensitivity, the minimum spatial resolution (high spatial resolution) and the quasi-linear curve.

The best geometry tested has a spatial resolution of 2 × 2 mm, a penetration depth of 700 µm and a quasi-linear response in the measuring range. This geometry was tested by means of conductance and capacitance static experiments. From these experiments, it could be determined that conductance and the capacitance systems are promising for measuring water film thickness in an oil–water flow.

Several measurement techniques such as micro-PIV, planar laser-induced fluorescence and planar conductive or capacitive sensors that are supposed to be adaptable to the liquid–liquid flow have been proposed recently. Micro-PIV and planar-induced fluorescence need transparent pipes and fluids. On the other hand, conductive or capacitive methods have been only applied to low viscosity fluids. In that context, this paper proposes to study a new technique for non-intrusive measurement of the liquid-liquid flow. The main goal is the validation of the new planar sensor as a reference tool for the development of instrumentation for oilfield application.

Oil-water two-phase flow is the most prevalent medium in oil field gathering pipelines, and the corrosion of pipelines is often highly localized. Therefore, the purpose of this paper is to investigate the corrosion behavior of 20# pipeline steel in the oil-water stratified liquids, vary the water content of the upper emulsion and study the difference of the corrosion process.

Combine the wire beam electrodes (WBE) technique and the corrosion weight loss method to investigate the corrosion behavior of 20# steel in produced water simulation fluid and oil-water stratified liquids, and a corrosion mechanism model was established for analysis and explanation.

The results of mass loss experiments showed that the average corrosion rate increased with the increase in the water content of the upper emulsion. The corrosion current distribution maps indicated that the most serious corrosion occurred in the produced water simulation liquid, and the corrosion process showed the law of waterline corrosion. In addition, it was also found that the corrosion of the WBE in the stratified liquids had obvious non-uniformities. The electrode wires at the oil-water interface suffered from severe corrosion, caused by the dissolution of crude oil acids in water and the uneven distribution of oxygen in the corrosive medium.

The WBE technique provides a deep insight into the corrosion phenomena at the oil-water interface, which is helpful for characterization of the non-uniformity of corrosion parameters and evaluating the risks of multiphase corrosive media.

The purpose of this paper is to investigate the corrosion behavior of X65 steel in the CO₂-saturated oil/water environment using mass loss method, potentiodynamic polarization technique and characterization of the corroded surface techniques.

The weight loss analysis, electrochemical study and surface investigation were carried out on X65 steel that had been immersed in the CO₂/oil/water corrosive medium to understand the corrosion behavior of gathering and transportation pipeline steel. The weight loss tests were carried out in a 3 L autoclave, and effects of water cut and temperature on the CO₂ corrosion rate of X65 steel were studied. Electrochemical studies were carried out in a three-electrode electrochemical cell with the test temperature was 60°C, and the CO₂ partial pressure was 1 atm by recording open circuit potential/time and potentiodynamic polarization characteristics. The surface and cross-sectional morphologies of corrosion product scales were characterized using scanning electron microscopy. The phases of corrosion product scales were investigated using x-ray diffraction.

The results showed that due to the wetting and adsorption of crude oil, the corrosion morphology of X65 steel changed under different water cuts. When the water cut of crude oil was 40-50 per cent, uniform corrosion occurred on the steel surface, accompanied by local pitting. While the water cut was 70-80 per cent, the resulting corrosion product scales were thick, loose and partial shedding caused platform corrosion. When the water cut was 90 per cent, the damaged area of platform corrosion was enlarged. Crude oil can hinder the corrosion scales from being dissolved by the corrosive medium, and change dimension and accumulation pattern of the crystal grain, thickness and structure of the corrosion scales. Under the corrosion inhibition effect of crude oil, the temperature sensitive point of X65 steel corrosion process moved to low temperature, appeared at about 50°C, lower corrosion rate interval was broadened and the corrosion resistance of X65 steel was enhanced.

The results can be helpful in selecting the applicable corrosion inhibitors and targeted anti-corrosion measures for CO₂-saturated oil/water corrosive environment.

Among the many influencing effects that the medium has on the CO₂ corrosion of carbon steel, flow is one of the most important because it can determine the formation of corrosion product scales and its stabilisation, thus influencing the attack morphology and corrosion rate. This paper aims to summarise some factors affecting aqueous CO₂ corrosion and the laboratory methodologies to evaluate one of the most important, the flow, with an emphasis on less costly rotating cage (RC) laboratory methodology.

Regarding the key factors affecting CO₂ corrosion, both well-established factors and some not well addressed in current corrosion prediction models are presented. The wall shear stress (WSS) values that can be obtained by laboratory flow simulation methodologies in pipelines and its effects over iron carbonate (FeCO₃) scales or inhibition films are discussed. In addition, promising applications of electrochemical techniques coupled to RC methodology under mild or harsh conditions are presented.

More studies could be addressed that also consider both the salting-out effects and the presence of oxygen in CO₂ corrosion. The RC methodology may be appropriate to simulate a WSS close to that obtained by laboratory flow loops, especially when using only water as the corrosive medium.

The WSS generated by the RC methodology might not be able to cause destruction of protective FeCO₃ scales or inhibition films. However, this may be an issue even when using methodologies that allow high-magnitude hydrodynamic stresses.

A novel approach using artificial neural networks (ANNs) for predicting temperature profiles evaluated 27 wells in the Gulf of Mexico. Two artificial neural network models were developed that predict the temperature of the flowing fluid at any depth in flowing oil wells. Back propagation was used in training the networks. The networks were tested using measured temperature profiles from the 27 oil wells. Both neural network models successfully mapped the general temperature‐profile trends of naturally flowing oil wells. The highest accuracy was achieved with a mean absolute relative percentage error of 6.0 per cent. The accuracy of the proposed neural network models to predict the temperature profile is compared to that of existing correlations. Many correlations to predict temperature profiles of the wellbore fluid, for single‐phase or multiphase flow, in producing oil wells have been developed using theoretical principles such as energy, mass and momentum balances coupled with regression analysis. The Neural Network 2 model exhibited significantly lower mean absolute relative percentage error than other correlations. Furthermore, in order to test the accuracy of the neural network models to that of Kirkpatrick’s correlation, a mathematical model was developed for Kirkpatrick’s flowing temperature gradient chart.