A laboratory investigation of horizontal well heavy oil—water flows

Experimental simulations of model well‐bore flows in laboratory pipelines show that frictional energy losses (i.e., pressure drops) are reduced when water is present with heavy oil. The reduction has been shown to increase with the water fraction. The mixtures are not oil in water emulsions in the classical sense of the term. At the low axial velocities which characterize wellbore flows, the flow regime is inherently intermittent. Using a variety of methods the structure of the flow has been examined to identify the flow regime and the cause of the reduced pressure gradients. It has been found that the water travels as large slugs and that oil is invariably present at the wall when the mixture flows through a steel pipe. The evidence suggests that a significant fraction of the oil is transported within the water slugs. A tentative flow regime boundary between the regions of intermittent and continuous water‐assisted flow is proposed in terms of the mixture Froude number and the injected water fraction.     

Factors Governing Friction Losses in Self‐lubricated Transport of Bitumen Froth: 1. Water Release

Syncrude Canada Ltd. transports bitumen froth, a viscous intermediate product of the oil sand extraction process, 35 km via pipeline. Pipeline transport is feasible because some of the water that occurs naturally in the froth forms a thin lubricating layer around a bitumen‐rich core, thereby greatly reducing friction losses and transportation costs. In this paper, the effect of froth composition (namely, water content) on the formation of the lubricating layer is reported. Tests were conducted with a 25 mm diameter pipe loop and a concentric cylinder froth rheometer. Measurements of pressure gradient and water holdup (free water fraction), along with visual observations, showed that froth containing a lower total water content yielded less free water to the lubricating layer. In the froth rheometer, the conditions for which stable, self‐lubricated flow could be maintained were comparable to those required to maintain self‐lubricated flow in the 25 mm pipe loop.     

Low Inclination Oil‐water Flows

Two‐phase liquid flows at +5° inclination from the horizontal were studied experimentally for mixture velocities between 0.7 and 2.5 m/s and input oil fractions between 10% and 90%. The results were compared with a two‐fluid model that includes entrainment. The investigations were performed in a 38‐mm ID stainless steel test section, with water and oil as test fluids. Dual continuous flow (both phases remain continuous with inter‐dispersion) prevailed, while the two‐phase pressure gradient was found lower than the single‐phase oil or water. At low mixture velocities the velocity ratio increased with oil fraction while at high ones it decreased. Compared to horizontal flow, water holdup was higher and frictional pressure gradient lower.     

Applications of Low Field NMR Techniques in the Characterization of Oil Sand Mining,Extraction and Upgrading Processes

A number of techniques have previously been developed that use low field nuclear magnetic resonance (NMR) relaxometry for conventional and heavy oil reservoir characterization. In the current work, the adaptation of these algorithms for use in the oil sands industry is presented. NMR based methods have been developed for identification of water and bitumen content in ore and froth samples. Consistent algorithms have been used to analyze over 500 ore samples and 50 froth samples from the Athabasca oil sands in northern Alberta. Preliminary analyses are shown, with applications for in‐situ fluid determination using NMR logging tools and improved process control in oil sands processing plants.     

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 = 20.1 mN/m) not previously reported was used in a 25.4 mm 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.     

Behavior of Pressure Gradient and Transient Pressure Signals during Liquid‐Liquid Two‐Phase Flow

Liquid‐liquid two‐phase flows are encountered in several process industries, multiphase reactors and oil industries. In each of these applications, identification of flow patterns poses a challenging problem and many efforts are directed towards developing suitable devices for this purpose. In the present work, attempts have been made to use pressure gradient and transient pressure signals to study flow patterns during the simultaneous flow of two liquids through a horizontal pipe. It is observed that the slope of the pressure gradient curves as a function of fluid superficial velocities is a weak function of the flow pattern. However, the variation of the slope with the pattern transition is much more significant when the pressure gradient is normalized with respect to only kerosene flow through the pipe (Δp_TP/Δp_KO). Further attempts have been made to identify flow patterns from transient pressure signals and the statistical analysis of these random signals has been undertaken. The PDF analysis and the wavelet multiresolution technique have been adapted to explain the signals in detail. The flow regimes identified are smooth stratified, wavy stratified, plug flow, ‘three‐layer' flow, ‘oil dispersed in water and water' and ‘oil and water in oil' flow patterns. The signal characteristics are depicted for each flow pattern.     

Liquid‐Liquid Stratified Flow through Horizontal Conduits

The stratified configuration is one of the basic and most important distributions during two phase flow through horizontal pipes. A number of studies have been carried out to understand gas‐liquid stratified flows. However, not much is known regarding the simultaneous flow of two immiscible liquids. There is no guarantee that the information available for gas‐liquid cases can be extended to liquid‐liquid flows. Therefore, the present work attempts a detailed investigation of liquid‐liquid stratified flow through horizontal conduits. Gas‐liquid flow exhibits either smooth or wavy stratified orientations, while liquid‐liquid flow exhibits other distinct stratified patterns like three layer flow, oil dispersed in water, and water flow, etc. Due to this, regime maps and transition equations available for predicting the regimes in gas‐liquid flow cannot be extended for liquid‐liquid cases by merely substituting phase physical properties in the equations. Further efforts have been made to estimate the in‐situ liquid holdup from experiments and theory. The analysis considers the pronounced effect of surface tension, and attempts to modify the Taitel‐Dukler model to account for the curved interface observed in these cases. The curved interface model of Brauner has been validated with experimental data from the present work and those reported in literature. It gives a better prediction of liquid holdup in oil‐water flows and reduces to the Taitel‐Dukler model for air‐water systems.     

A preliminary study of interfacial areas in vertical cocurrent,two-phase upflow

Pseudo-first order chemical absorption was used as the basis for determining the effective interfacial area available for mass transfer in gas-liquid, cocurrent, upward pipe flow. The study, which was performed in a 2.54 cm I.D. tube, encompassed the slug and froth flow regimes. The interfacial area displayed a strong dependence upon the coordinates of the flow regime map proposed by Oshinowo and Charles⁽¹⁶⁾. In addition, the systematic variation of surface area could be rationalized on the basis of flow regime geometry. Unfortunately the data could not be used to assess previous surface area models due to the unresolved diameter dependence of these models. Observations are also made concerning the apparently significant effect of chemical composition on interfacial surface area, and concerning the inadequacy of the popular methods used for estimating frictional pressure drop in vertical two-phase flows.     

Experimental study on the restart of core-annular flow

We show the results of an experimental campaign to study the pressure drop during the restart of a core-annular flow from a stratified configuration. In normal core annular flow operations, due to fouling or pump failures, a core flow may not be sustained anymore and hence it stratifies. Since the pressure drops connected to the stratified flow regime are much larger than the ones of core annular, the flow suddenly stops. To restart it there are two possibilities: one is to try to provide a higher pressure gradient trying to restore the flow of water and oil, the other is to clean the pipe using water only: in both cases an attachment of a thin layer of oil on the pipe internal wall occurs and the pressure drop for water only or oil–water are higher than the previous ones with clean pipe wall. We focused our attention on the cleaning by water only and we provide experimental data on the evolution of the pressure drop as function of time in order to find when the pipe could be considered as perfectly cleaned or, at least, when the pressure drop are low enough to restart the oil flow. The experimental results are finally compared with a two-fluid model available in literature.     

Wettability of fine solids extracted from bitumen froth

Production of synthetic crude oil from oil sands deposits in northern Alberta involves open pit mining, mixing the mined ore with water, extraction of aerated bitumen from the slurry, removal of water and solids from the froth formed, and upgrading heavy bitumen to liquid hydrocarbons. The success of the froth treatment operation, aimed at removal of fine solids and water from the bituminous froth, depends on the control of wettability of fine solids by the aqueous phase. Fine solids were extracted from bitumen froth by heptane. The partition of the extracted solids in aqueous, organic, and interphases was measured, and the wettability of the solids by water in various diluents was evaluated from contact angle measurements. The effect of diluent composition, sample drying, and surface washing on the wettability and fine particle partition was examined. The partition of fine particles correlated well with their wettabilities, and the results were found to be useful for interpreting the observations from froth treatment practice.     

RHEOLOGICAL PROPERTIES AND FLOW OF CONCENTRATED DISPERSE MEDIA. II - STEADY AND UNSTEADY FLOW ANALYSIS OF HEAVY CRUDE OIL EMULSIONS

Experimental study of steady flows of heavy crude oil emulsions in rectilinear ducts provides evidence of a non newtonian behaviour in good agreement with viscometric rheological data. Superimposing an unsteady flow on the mean one, the mean flow rate is shown to be strongly increased under conditions depending on the frequency and the values of the mean and oscillatory components of the pressure gradient. The mean features of such an enhancement are then interpreted in relation to the rheological behaviour of the fluid.     

RHEOLOGICAL PROPERTIES AND FLOW OF CONCENTRATED DISPERSE MEDIA. II - STEADY AND UNSTEADY FLOW ANALYSIS OF HEAVY CRUDE OIL EMULSIONS

Experimental study of steady flows of heavy crude oil emulsions in rectilinear ducts provides evidence of a non newtonian behaviour in good agreement with viscometric rheological data. Superimposing an unsteady flow on the mean one, the mean flow rate is shown to be strongly increased under conditions depending on the frequency and the values of the mean and oscillatory components of the pressure gradient. The mean features of such an enhancement are then interpreted in relation to the rheological behaviour of the fluid.     

塔板上操作工况的过渡和雾沫夹带转变点

塔板上两相操作工况与雾沫夹带量的变化相关。在某气速下连续改变液流速率,雾沫夹带量呈马鞍形的变化,最低点所对应的清液深度,Zc约30—40mm,定义为“雾沫夹带转变点”。 当清液深度低于转变点,两相处于喷射或喷射主导工况;反之,两相处于泡沫或泡沫主导工况,雾沫夹带转变点即两种工况的过渡点。工况过渡不是突变而是渐变。文中对影响雾沫夹带变化的因素及工况过渡的特点进行了讨论。 作者提出,流行的雾沫夹带计算式——Hunt公式一般只适用于泡沫工况而不适用于喷射工况的操作过程。     

Distribution of clay minerals in the process streams produced by the extraction of bitumen from Athabasca oil sands

This study investigates the affinity of clay minerals in oil sands for the water‐continuous tailings and hydrocarbon‐continuous froth streams produced from the extraction of bitumen from oil sands. Clay minerals in oil sands processing impact bitumen flotation in separation vessels, emulsion formation during froth treatment, and fine tailings behaviour. X‐ray diffraction of oriented clay slides and random powder samples were used to quantify the clay minerals in the oil sands ore and process streams. Particle size distribution and clay activity balances were also conducted around the extraction process. The degree of partitioning during the conditioning and flotation stages in a batch extractor was determined by the surface properties of the clay minerals present. The water‐continuous tailings stream was further separated into fine and coarse tailings fractions through sedimentation. The bulk of the clay minerals reported to the fine tailings stream. Illite and mixed layered illite‐smectite partitioned less to the hydrocarbon‐continuous froth than kaolinite. Also, the illite‐smectite in the froth stream appeared to be different from the illite‐smectite in the water continuous streams.     

Anomalous friction in slurry flows

Experiments conducted with water slurries of 1 mm particles of specific gravity 1.59 in a laboratory pipeline 0.105 m in diameter have provided evidence of a change in the friction mechanism at velocities above 3 m/s. These flows were stratified and at low velocities the frictional pressure gradients were in satisfactory agreement with the predictions of the conventional two‐layer model. However at higher velocities the friction is substantially lower than predicted. Measurements of concentration and velocity distributions within the pipe show that no major change in flow regime occurs concurrently with the change in the friction mechanism. It appears that the effect is due to a change in the nature of the particle‐wall interaction, of a type which suggests that an inward‐acting force affects the particles adjacent to the wall.     

气液固三相并流系统流型的混沌识别

运用确定性混沌分析技术，研究了气液固三相并流系统散式鼓泡流、聚式鼓泡流、柱塞流、泡沫流及环状流压力波动信号的混沌动力学行为。结果表明，吸引子可以用来表征气液固三相并流系统的动力学行为，混沌特征参数相关维D2和K熵可以用来定量识别以上五种流型。以混沌定量识别为基础，给出了三相并流系统的流型图。     

Oil–water two‐phase flow in microchannels: Flow patterns and pressure drop measurements

This paper investigates oil–water two‐phase flows in microchannels of 793 and 667 µm hydraulic diameters made of quartz and glass, respectively. By injecting one fluid at a constant flow rate and the second at variable flow rate, different flow patterns were identified and mapped and the corresponding two‐phase pressure drops were measured. Measurements of the pressure drops were interpreted using the homogeneous and Lockhart–Martinelli models developed for two‐phase flows in pipes. The results show similarity to both liquid–liquid flow in pipes and to gas–liquid flow in microchannels. We find a strong dependence of pressure drop on flow rates, microchannel material, and the first fluid injected into the microchannel.     

An investigation of the effect of air addition during oil sand conditioning

Bitumen aeration was studied by flooding samples of medium grade oil sand with de‐ionized water under both ambient and high vacuum conditions. The samples were then agitated on a shaker table. Subsequent analysis revealed the presence or absence of an air gap in the sample container was the single most important factor in determining the overall bitumen recovery. Furthermore, samples that were flooded while under high vacuum produced slightly less bitumen compared to samples flooded at atmospheric pressure. This suggests that oil sand that is not under high vacuum when flooded with water contains some amount of indigenous air (see introduction) that would aid in bitumen flotation.     

Effect of molecular weight and charge density on the performance of polyacrylamide in low‐grade oil sand ore processing

The effect of charge density and molecular weight (MW) of partially hydrolyzed polyacrylamide (HPAM) polymers on their performance in processing low‐grade oil sand ores was investigated. Bitumen extraction and tailings settling tests were carried out and an atomic force microscope (AFM) was used to directly measure the bitumen‐solid and solid‐solid interaction forces. It was found that HPAM polymers with a low MW acted as dispersants in the bitumen extraction process, resulting in low bitumen recovery and slow tailings settling but improved froth quality. In contrast, the use of HPAM polymers with a high MW improved both bitumen recovery and tailings settling but deteriorated froth quality. To achieve high bitumen recovery and fast tailings settling, a HPAM polymer must have a low to medium charge density (～30%) and a high MW (17.5 million Daltons). A stronger clay‐bitumen adhesion force normally resulted in a lower bitumen recovery. Fast tailings settling was achieved in the presence of a strong solid‐solid adhesion force.     

Numerical Simulation of Oil‐Water Core Annular Flow in a U‐Bend Based on the Eulerian Model

The oil‐water core annular flow through a U‐bend is simulated by computational fluid dynamics based on the Eulerian model. More flow parameters and the effect of annulus thickness on core annular flow are discussed. Conformity between the simulated and experimental data is observed. The development of oil‐water core annular flow in the U‐bend is analyzed, and the distributions of pressure and velocity are discussed. Results of the Eulerian model and volume‐of‐fluid (VOF) model are compared and the influence of oil properties on total pressure gradient is investigated. The suitable range of annulus thickness is identified. The results provide suitable operation conditions for designing the U‐bend pipefitting.