Oil Velocities Research Articles

Pressure drop and holdup predictions in horizontal oil–water flows for curved and wavy interfaces

In this work a modified two-fluid model was developed based on experimental observations of the interface configuration in stratified liquid–liquid flows. The experimental data were obtained in a horizontal 14mmID acrylic pipe, for test oil and water superficial velocities ranging from 0.02m/s to 0.51m/s and from 0.05m/s to 0.62m/s, respectively. Using conductance probes, average interface heights were obtained at the pipe centre and close to the pipe wall, which revealed a concave interface shape in all cases studied. A correlation between the two heights was developed that was used in the two-fluid model. In addition, from the time series of the probe signal at the pipe centre, the average wave amplitude was calculated to be 0.0005m and was used as an equivalent roughness in the interfacial shear stress model. Both the interface shape and roughness were considered in the two-fluid model together with literature interfacial shear stress correlations. Results showed that the inclusion of both the interface curvature and the equivalent roughness in the two-fluid model improved its predictions of pressure drop and interface height over the range of studied superficial oil and water velocities. Compared to the two-fluid model with other interfacial shear stress correlations, the modified model performed better particularly for predicting pressure drop.

Applying a Smart Technique for Accurate Determination of Flowing Oil-Water Pressure Gradient in Horizontal Pipelines

Two-phase flow of liquids in pipelines is crucial subject in many industries such as chemical and petroleum. Accurate prediction of pressure gradient will lead to a better design of an energy efficient transportation system. Although numerous studies for prediction of two-phase flowing pressure drop have been reported in the literature, the accurate prediction of this parameter has been a topic of debate in many research areas. In this article, a novel model based on least square support vector (LSSVM) was proposed for calculation of two-phase flowing pressure drop in horizontal pipes. The inputs of this model are oil and water superficial velocities, pipe diameter, pipe roughness, and oil viscosity. To develop and test the model, more than 700 experimental dataset from open literature were utilized. The results of proposed model were compared against the well-known empirical correlations. Statistical error analysis showed that the LSSVM model outperforms existing predictive models. Finally, an outlier diagnosis was performed to detect the doubtful experimental.

Correlations for Prediction of Pressure Gradient of Liquid-Liquid Flow Through a Circular Horizontal Pipe

We report a detailed investigation on the measurement and prediction of pressure gradient characteristics of moderately viscous lubricating oil-water flow through a horizontal pipe of 0.025 m internal diameter. Experiments are carried out over a wide range of phase velocities of both oil (USO = 0.015–1.25 m/s) and water (USW = 0.1–1.1 m/s). Experimental pressure gradients yield significant errors when fitted to the existing correlations, which are largely used for gas-liquid flow. To predict pressure gradient characteristics for liquid-liquid flow, the existing correlations need to be modified. We propose two correlations, based on the Lockhart–Martinelli's approach (by modifying the correlation between the Lockhart–Martinelli parameter and a two-phase multiplier suitable for the present system) and dimensionless analysis, following the Buckingham's Pi-theorem. We observe significant improvement in the prediction of pressure gradient. The correlation based on the dimensionless analysis predicts better with an average absolute error of 17.9%, in comparison with the modified Lockhart–Martinelli correlation, which yields an average error of 22%, covering all the flow patterns. The present analysis shows better prediction as compared to two-fluid model Zhang et al. (2012, “Modeling High-Viscosity Oil/Water Concurrent Flow in Horizontal and Vertical Pipes,” SPE J., 17(1), pp. 243–250) and Al-Wahaibi (2012, “Pressure Gradient Correlation for Oil-Water Separated Flow in Horizontal Pipes,” Exp. Therm. Fluid Sci., 42, pp. 196–203) work.

Experimental Study on the Flow Regimes and Pressure Gradients of Air-Oil-Water Three-Phase Flow in Horizontal Pipes

An experimental investigation has been carried out to study the flow regimes and pressure gradients of air-oil-water three-phase flows in 2.25 ID horizontal pipe at different flow conditions. The effects of water cuts, liquid and gas velocities on flow patterns and pressure gradients have been studied. The experiments have been conducted at 20°C using low viscosity Safrasol D80 oil, tap water and air. Superficial water and oil velocities were varied from 0.3 m/s to 3 m/s and air velocity varied from 0.29 m/s to 52.5 m/s to cover wide range of flow patterns. The experiments were performed for 10% to 90% water cuts. The flow patterns were observed and recorded using high speed video camera while the pressure drops were measured using pressure transducers and U-tube manometers. The flow patterns show strong dependence on water fraction, gas velocities, and liquid velocities. The observed flow patterns are stratified (smooth and wavy), elongated bubble, slug, dispersed bubble, and annular flow patterns. The pressure gradients have been found to increase with the increase in gas flow rates. Also, for a given superficial gas velocity, the pressure gradients increased with the increase in the superficial liquid velocity. The pressure gradient first increases and then decreases with increasing water cut. In general, phase inversion was observed with increase in the water cut. The experimental results have been compared with the existing unified Model and a good agreement has been noticed.

PREDICTION OF HORIZONTAL OIL-WATER FLOW PRESSURE GRADIENT USING ARTIFICIAL INTELLIGENCE TECHNIQUES

In oil-water flow, the two-fluid and the homogeneous models are commonly used to predict the pressure gradient. However, these models fail in many cases to predict the pressure gradient, especially in dual continuous flow. In this work, an artificial neural network (ANN) model with five inputs—oil and water superficial velocities, pipe diameter, pipe roughness, and oil viscosity—was developed to predict the pressure gradient of horizontal oil-water flow based on a databank of around 765 measurements collected from the open literature. Statistical analysis showed that the ANN model has an average error of 0.30%, average absolute error of 2.9%, and standard deviation of 7.6%. A comparison with the two-fluid model, the homogeneous model, and the Al-Wahaibi (2012) correlation showed that the ANN model better predicts the pressure gradient data over a wide range of superficial oil (U so = 0.05–3.0 m/s) and water velocities (U sw = 0.05–2.7 m/s), oil viscosity values (1–35 cp), pipe diameters (14–82.8 mm), and different pipe materials.

Experimental Study of High-Viscosity Oil/Water/Gas Three-Phase Flow in Horizontal and Upward Vertical Pipes

Summary In this experimental study, measurements and observations have been carried out for high-viscosity oil/water/gas three-phase flows in horizontal and upward vertical pipes. Oil with viscosities between 0.15 and 0.57 Pa·s corresponding to temperatures from 37.8 to 15.6°C, filtered tap water, and natural gas at 2.59 MPa pressure are used as the three phases. Superficial oil and water velocities range from 0.1 to 1.0 m/s, and superficial gas velocity varies from 1.0 to 5.0 m/s. The internal diameter of the pipe is 5.25 cm. The experimental measurements include pressure gradient and liquid holdup. The flow-pattern and slug characteristics are observed and the images are recorded with a high-speed video camera system through a high-pressure sapphire window. The experimental results are compared with the predictions of the Zhang and Sarica (2006) unified model (UM), and the discrepancies are identified.

Large probe arrays for measuring mean and time dependent local oil volume fraction and local oil velocity component distributions in inclined oil-in-water flows

Arrays of dual-sensor and four-sensor needle conductance probes have been used to measure the mean and time dependent local properties of upward inclined, bubbly oil-in-water flows (also known as dispersed oil-in-water flows) in a 153mm diameter pipe. The flow properties that were measured were (i) the local in-situ oil volume fraction α; (ii) the local oil velocity uo in the axial direction of the pipe (the Z direction); and (iii) the local oil velocity uY in the direction from the lower side of the inclined pipe to its upper side (the Y direction). Oil velocities in the X direction (orthogonal to the Y and Z directions) were found to be negligible. For all of the flow conditions investigated it was found that the mean value of α varied from a maximum value at the upper side of the inclined pipe to a minimum value at the lower side, and that the rate of decrease of this mean value of α with distance in the −Y direction became greater as the pipe inclination angle θ from the vertical was increased. It was also found that the mean value of uo was greatest at the upper side of the inclined pipe and decreased towards the lower side of the inclined pipe, the rate of decrease with distance in the −Y direction again becoming greater as θ was increased. For θ=45o, a water volumetric flow rate Qw=16.38m3h−1, an oil volumetric flow rate Qo=6.0m3h−1 and using a sampling period T=0.05s over a total time interval of 60s, it was found that at the upper side of the inclined pipe the standard deviation in uo was 31.6% of the mean value of uo. Furthermore for T=0.05s, θ=30o, Qw=16.38m3h−1 and Qo=6.0m3h−1 it was found that the standard deviation in the cross-pipe oil velocity component uY was approximately equal to the standard deviation in the axial velocity component uo. These large temporal variations in the local flow properties have been attributed to the presence of large scale Kelvin–Helmholtz waves which intermittently appear in the flow. It is believed that the techniques outlined in this paper for measuring the standard deviation of local flow properties as a function of the sampling period T will be of considerable value in validating mathematical models of time dependent oil–water flows. It should be noted that the principal focus of this paper is on the measurement techniques that were used and the methods of data analysis rather than the presentation of exhaustive experimental results at numerous different flow conditions.

High viscosity effects on characteristics of oil and gas two-phase flow in horizontal pipes

The flow characteristics of high viscosity oil and gas flow show several significant differences with those of low viscosity liquid. Effects of high viscosity oil on characteristics of oil and gas flow are identified. The present experiments are performed on the flow facility which consists of a test section of 26mm ID and a 5.5m long horizontal pipe. A range of liquid viscosity from 1000cP to 7500cP is investigated. The superficial oil and gas velocities vary from 0.06m/s to 0.5m/s and from 0.3m/s to 12.0m/s respectively. The resulting flow patterns are identified by Electrical Capacitance Tomography (ECT) and confirmed by videos recorded during the experiments. The pressure and liquid holdup data are obtained by using pressure transducers and ECT system. The experimental results are compared with existing models and show significant discrepancies between low and high viscosity liquid and gas flows.

Evaluation of solitary waves as a mechanism for oil transport in poroelastic media: A case study of the South Eugene Island field, Gulf of Mexico basin

Hydrocarbons in shallow reservoirs of the Eugene Island 330 field in the Gulf of Mexico basin are thought to have migrated rapidly along low permeability sediments of the Red fault zone as discrete pressure pulses from source rocks at depths of about 4.5 km. The aim of this research was to evaluate the hypothesis that these pressure pulses represent solitary waves by investigating the mechanics of solitary wave formation and motion and wave oil transport capability. A two-dimensional numerical model of Eugene Island minibasin formation predicted overpressures at the hydrocarbon source depth to increase at an average rate of 30 Pa/yr, reaching 52 MPa by the present day and oil velocities of 10−12 m/yr, far too low for kilometer scale oil transport to fill shallow Plio-Pleistocene reservoirs within the 3.6 million year minibasin history. Calculations from a separate one-dimensional model that used the pressure generation rate from the two-dimensional model showed that solitary waves could only form and migrate within sediments that have very low permeabilities between 10−25 and 10−24 m2 and that are highly overpressured to 91–93% of lithostatic pressure. Solitary waves were found to have a maximum pore volume of 105 m3, to travel a maximum distance of 1–2 km, and to have a maximum velocity of 10−3 m/yr. Based on these results, solitary waves are unlikely to have transported oil to the shallowest reservoirs in the Eugene Island field in a poroelastic fault gouge rheology at the pressure generation rates likely to have been caused by disequilibrium compaction and hydrocarbon generation. However, solitary waves could perhaps be important agents for oil transport in other locations where reservoirs are closer to the source rocks, where the pore space is occupied by more than one fluid, or where sudden fracturing of overpressured hydrocarbon source sediments would allow the solitary waves to propagate as shock waves.

Experimental study on the effect of drag reducing polymer on flow patterns and drag reduction in a horizontal oil–water flow

In this study, a HMW anionic co-polymer of 40:60wt/wt NaAMPS/acrylamide was used as a drag reducing polymer (DRP) for oil–water flow in a horizontal 25.4mm ID acrylic pipe. The effect of polymer concentration in the master solution and after injection in the main water stream, oil and water velocities, and pipe length on drag reduction (DR) was investigated. The injected polymer had a noticeable effect on flow patterns and their transitions. Stratified and dual continuous flows extended to higher superficial oil velocities while annular flow changed to dual continuous flow. The results showed that as low as 2ppm polymer concentration was sufficient to create a significant drag reduction across the pipe. DR was found to increase with polymer concentration increased and reached maximum plateau value at around 10ppm. The results showed that the drag reduction effect tends to increase as superficial water velocity increased and eventually reached a plateau at Usw of around 1.3m/s. At Usw>1.0m/s, the drag reduction decreased as Uso increased while at lower water velocities, drag reduction is fluctuating with respect to Uso. A maximum DR of about 60% was achieved at Uso=0.14m/s while only 45% was obtained at Uso=0.52m/s. The effectiveness of the DRP was found to be independent of the polymer concentration in the master solution and to some extent pipe length. The friction factor correlation proposed by Al-Sarkhi et al. (2011) for horizontal flow of oil–water using DRPs was found to underpredict the present experimental pressure gradient data.

Wax Deposition in Stratified Oil/Water Flow

While diffusion as the major mechanism for wax deposition has been investigated in past decades, wax gelation has mostly been studied in quiescent conditions and is considered to be less significant than diffusion in flow conditions. In this study, gelation has been observed as a major mechanism for the formation of wax deposits in oil/water stratified flow. The experiments are carried out in a state-of-the-art flow loop using a North Sea gas condensate and formation water. The flow map study using reflex camera and X-ray tomography reveals that most of the completely stratified flows occur at low total flow rates of oil and water, which correspond to low shear stresses at the wall. It was found that the carbon number distributions of the wax deposits formed in this region have very low fractions of heavy components and are very close to the distribution of the deposit that is only formed by gelation. It was further revealed that the deposit thickness increases with increasing degree of gelation, which corresponds to decreasing shear stress of the fluids at the wall. This finding is consistent with previous studies from single-phase experiments where lower oil velocities are found to result in much higher deposit thicknesses and low wax fractions in the deposits.

CFD simulation of core annular flow through sudden contraction and expansion

In the present work, a computational fluid dynamic simulation has been performed to investigate core annular flow through sudden contraction and expansion. Core annular flow of lubricating oil and water has been simulated using VOF technique and a satisfactory match between simulated data and experimental results has been obtained. A detailed study has been performed to generate the profiles of velocity, pressure and volume fraction over a wide range of oil and water velocities for an abrupt expansion and contraction. Asymmetric nature of velocity across the radial plane is observed for both the cases. The fouling characteristic of lubricating oil at sudden expansion is also analyzed. The model predicts that fouling can be minimized by increasing the water intake or the pipe diameter.

Effect of oil viscosity on the flow structure and pressure gradient in horizontal oil–water flow

The flow patterns and pressure gradient of immiscible liquids are still subject of immense research interest. This is partly because fluids with different properties exhibit different flow behaviours in different pipe's configurations under different operating conditions. In this study, a combination of oil–water properties (σ=20.1mN/m) not previously reported was used in a 25.4mm acrylic pipe. Experimental data of flow patterns, pressure gradient and phase inversion in horizontal oil–water flow are presented and analyzed together with comprehensive comments. The effect of oil viscosity on flow structure was assessed by comparing the present work data with those of Angeli and Hewitt (2000) and Raj et al. (2005). The comparison revealed several important findings. For example, the water velocity required to initiate the transition to non-stratified flow at low oil velocities increased as the oil viscosity increased while it decreased at higher oil velocities. The formation of bubbly and annular flows and the extent of dual continuous region were found to increase as the oil–water viscosity ratio increased. Dispersed oil in water appeared earlier when oil viscosity decreased.The effect of oil viscosity on pressure gradient was also investigated by comparing the results with Angeli and Hewitt (1998) and Chakrabarti et al. (2005). One of the main findings is the large difference between the pressure gradient results which is attributed to the difference in oil viscosity. The differences between the results become bigger at higher oil velocities. The largest difference in pressure values was observed in flow region where oil is the continuous phase. On the contrary, for dispersed oil in water (Do/w), the pressure gradient values observed at the same conditions are approximately the same. A simple correlation was developed to predict the pressure gradient in this regime. The correlation was validated using new experimental data.Finally, the effect of oil viscosity on pressure gradient prediction was investigated using the two flow model for stratified flow and the homogenous model for oil dispersed in water. Both models showed better prediction for the low oil viscosities.

Experimental study on the transition between stratified and non-stratified horizontal oil–water flow

The effect of oil and water velocities, pipe diameter and oil viscosity on the transition from stratified to non-stratified patterns was studied experimentally in horizontal oil–water flow. The investigations were carried out in a horizontal acrylic test section with 25.4 and 19 mm ID with water and two oil viscosities (6.4 and 12 cP) as test fluids. A high-speed video camera was used to study the flow structures and the transition. At certain oil velocity, stratified flow was found to transform into bubbly and dual continuous flows as superficial water velocity increased for both pipe diameters using the 12 cP oil viscosity. The transition to bubbly flow was found to disappear when the 6.4 cP oil viscosity was used in the 25.4 mm pipe. This was due to the low Eőtvős number. Transition to dual continuous flow occurred at lower water velocity for oil velocity up 0.21 m/s when 6.4 cP oil was used in the 25.4 mm ID pipe, while for U so > 0.21 m/s, the transition appeared at lower water velocity with the 12 cP oil. The effect of pipe diameter was also found to influence the transition between stratified and non-stratified flows. At certain superficial oil velocity, the water velocity required to form bubbly flow increased as the pipe diameter increased while the water velocity required for drop formation decreased as the pipe diameter increased. The maximum wave amplitude was found to grow exponentially with respect to the mixture velocity. The experimental maximum amplitudes at the transition to non-stratified flow agreed reasonably well with the critical amplitude model. Finally, it was found that none of the available models were able to predict the present experimental data at the transition from stratified to non-stratified flow.

Viscous oil–water flows in a microchannel initially saturated with oil: Flow patterns and pressure drop characteristics

Immiscible viscous liquid–liquid two-phase flow patterns and pressure drop characteristics in a circular microchannel have been investigated. Water and silicone oil with a dynamic viscosity of 863 mPa s were injected into a fused silica microchannel with an inner diameter of 250 μm. As the microchannel was initially filled with the silicone oil, an oil film was found to always form and remain on the microchannel wall. Different flow patterns were observed and classified over a wide range of water and oil flow rates. A flow pattern map is presented in terms of Re, Ca, and We numbers. Two-phase pressure drop data have also been collected and analyzed to develop a simple correlation for slug, annular and annular-droplet flow patterns in terms of superficial water and oil velocities.

석유생산 시스템에서 다상유동의 패턴 결정

본 연구에서는 포괄적 역학모델을 이용하여 석유 생산 시스템의 파이프 내 가스-오일 2상유동에 대한 유동패턴을 결정하였다. 2상의 유체는 운영 인자, 기하학적 변수, 유체 물성 등에 따라 특정의 유동패턴을 나타냈다. 광범위한 기액 겉보기 속도에 대하여 시스템의 인자들을 변화시키면서 유동패턴을 비교하였다. 다양한 인자들 중 경사각과 겉보기 속도가 파이프 내 가스-오일 2상유동의 유용패턴을 결정하는데 가장 지배적인 인자로 나타났다. 파이프 직경, 유체 물성 등의 인자들은 전이 경계선 부근을 제외하면 유동패턴 변화에 제한적인 영향 만을 미쳤다. 역학모델은 실험실 평가나 신뢰성있는 상관식 이용이 불가능할 때 유동패턴을 결정할 수 있는 유용한 도구이다. A comprehensive mechanistic model has been used to determine the flow pattern for gas-oil two-phase flow in pipes of petroleum production system. Depending on operational parameters, geometrical variables, and physical properties of the two phases, the two phases shows a specific flow patterns. For different parameters of the system, How pattern were compared for wide range of superficial velocities of oil and gas. In a variety of parameters, the inclinational angle and superficial velocities of oil and gas are the most dominant factors in determining the flow patterns for two-phase flow in pipelines. Other parameters such as pipe diameter and fluid properties have a limited effect on the change of flow patterns except for near transition. The mechanistic model is shown to be useful to determine the flow pattern in situations where either an experimental evaluation in a laboratory or reliable correlations are not available.

Simulation of core annular in return bends—A comprehensive CFD study

The present work reports a computational fluid dynamic analysis of core annular flow through return bends. Core annular flow of lubricating oil and water has been simulated using FLUENT 6.3.26. A satisfactory trend matching is observed between numerically obtained phase distribution and experiments. A comprehensive study has been made to generate the profiles of velocity, pressure, and volume fraction over a wide range of oil and water velocities. It has been observed that the oil core may foul the bend wall under certain operating conditions. Through computational simulations the operating zone safe from the risk of fouling has also been identified.

PIV investigation of oil–mineral interaction for an oil spill application

The mechanism of the formation of oil–mineral-aggregates (OMA) is studied by particle image velocimetry (PIV) to evaluate factors that may influence its application as an oil spill countermeasure. Both stationary and moving oil droplet strategies are employed. The movements of mineral particles near an oil droplet are captured and the interactions between mineral particles and oil droplets are visualized through the vector fields of mineral particles. The interaction between two different crude oils and three types of minerals were evaluated in this work. The results show that hydrophobicity plays an important role in the interaction between mineral particles and oil droplets. Hydrophobic minerals (modified Kaolin) tend to have more oil–mineral attraction than hydrophilic minerals (original Kaolin and diatomite). The results obtained in this work suggest that the medium South American crude was more repulsive against hydrophilic minerals (both Kaolin and diatomite) than the Alaska North Slope crude. On comparison to the original Kaolin, the vector field for oil in motion shows a more intensive interaction between modified Kaolin and Alaska North Slope oil and higher velocities maintained for a longer time period. The effect of dispersant is also tested. The results show that the oil-dispersant mixing method does not significantly change the oil surface property, while the water-dispersant mixing does.

Oil Droplet Motion Considering Breakup in an Aeroengine Bearing Chamber

Oil droplets can break up during flight and form many secondary droplets in an aero-engine bearing chamber due to aerodynamic drag forces. The motion properties of secondary droplets have significant influence on the two-phase oil/air flow phenomena in bearing chambers. In this work, oil droplet trajectories and velocities are developed by accounting for in-flight breakup. The droplet motion is modelled using a Lagrangian tracking method, and the trajectories and velocities are calculated by numerical integration of the oil particle momentum equation with forth-order Runge-Kutta scheme. The trajectories and velocities change abruptly at the breakup location, compared with unconsidering breakup. Subsequently, the effects of operating conditions on oil droplet motions are discussed. The numerical results show that the influence of breakup on oil droplet trajectory and velocity are considered necessarily when simulating two-phase oil/air flows in bearing chambers.

Simulation of core annular downflow through CFD—A comprehensive study

Water lubricated transport of high viscous oil is one of the energy efficient technologies in the energy sector. In the present work, a computational fluid dynamic study has been performed to simulate core annular downflow through vertical pipes. The CFD software package FLUENT 6.3.26 [1] is used and a satisfactory match between the simulated data and experimental results has been obtained. A comprehensive study has been made to generate the profiles of velocity, pressure, volume fraction and wall shear stress over a wide range of inlet oil and water velocities.