An experimental study of flow patterns pertinent to waxy crude oil-water two-phase flows

Accepted Manuscript An Experimental Study of Flow Patterns Pertinent to Waxy Crude Oil-Water Two-Phase Flows Ali Piroozian, Mahmoud Hemmati, Issham Ismail, Muhammad A. Manan, Mohammad M. Rashidi, Rahmat Mohsin PII: DOI: Reference:

S0009-2509(17)30135-5 http://dx.doi.org/10.1016/j.ces.2017.02.026 CES 13444

To appear in:

Chemical Engineering Science

Received Date: Revised Date: Accepted Date:

1 August 2016 29 January 2017 16 February 2017

Please cite this article as: A. Piroozian, M. Hemmati, I. Ismail, M.A. Manan, M.M. Rashidi, R. Mohsin, An Experimental Study of Flow Patterns Pertinent to Waxy Crude Oil-Water Two-Phase Flows, Chemical Engineering Science (2017), doi: http://dx.doi.org/10.1016/j.ces.2017.02.026

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An Experimental Study of Flow Patterns Pertinent to Waxy Crude Oil-Water TwoPhase Flows†

Ali Pirooziana,*, Mahmoud Hemmatia, Issham Ismaila, Muhammad A. Manana, Mohammad M. Rashidib,c, Rahmat Mohsind a

Department of Petroleum Engineering, Faculty of Chemical and Energy Engineering, Universiti

Teknologi Malaysia, Johor 81310, Malaysia b

Shanghai Key Lab of Vehicle Aerodynamics and Vehicle Thermal Management Systems, Tongji

University, 4800 Cao An Rd., Jiading, Shanghai 201804, China c

ENN-Tongji Clean Energy Institute of advanced studies, Tongji University, China

d

Malaysia Petroleum Resources Corporation (UTM-MPRC) Institute for Oil and Gas, Universiti

Teknologi Malaysia, Johor 81310, Malaysia

Keywords: oil-water two-phase flow, flow pattern, wax appearance temperature, waxy crude oil, water-in-oil emulsion, flow assurance †

Supported by Malaysia's Ministry of Higher Education (FRGS/4F136) and Universiti Teknologi Malaysia (RUG/01H68).

Corresponding author *Tel.: (+60) 127 444173. Fax: (+60) 75581463. E-mail: [email protected]. Notes The authors declare no competing financial interests.

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Abstract. Flow patterns encountered during the flow of a waxy crude oil and water in a horizontal pipeline were experimentally studied at a temperature 4 °C greater than the wax appearance temperature (WAT). The visual observation technique along with the analysis of the associated pressure drops and free water measurement were used to identify the flow patterns and their transitions. Designing a specific multiphase flow test facility and applying a newly proposed technique for controlling the mixture temperature also allowed the examination of the recently discovered phenomenon regarding the effect of emulsified water droplets on accelerating the wax crystallization process above the WAT under dynamic conditions. The results of this study showed the deposition of wax crystals on the pipe wall for some of the flow patterns which, by implication, authenticates the influence of emulsified water on elevating the WAT even in dynamic flow conditions. Classification of the flow patterns based on the wax deposition yielded an original flow pattern map composed of nine patterns among which new configurations were evidenced for annular flows. In addition, all the flow patterns were affected by the entrance effect and a layer of water-in-oil emulsion was observed for all the flow conditions. The influential parameters in the formation of such flow patterns are theoretically discussed in details. Since the waxy crude oil in two-phase flow is a relatively uncharted area of study, the results of this study can provide a platform for furthering research.

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1. Introduction

The liquid-liquid flow encompasses wide areas of the petroleum industry, starting from production wells to the refinery units. This highlights the importance of studying different aspects of oil-water two-phase flow to recognize and understand the potential impediments during the flow which are essential for having effective petroleum production plans. In this regard, pressure drop, liquid holdup and flow pattern have been studied as the major flow characteristics under different flow conditions (Angeli and Hewitt, 2000; Cai et al., 2012; Hanafizadeh et al., 2015; Lovick and Angeli, 2004; Rodriguez and Oliemans, 2006; Trallero et al., 1997; Vielma et al., 2008; Xu, 2007). Several correlations for pressure gradient prediction have been also proposed based on the experimental results which are in most cases incompatible for diverse fluids characteristics (AlWahaibi, 2012; Chakrabarti et al., 2005; Edomwonyi-Otu and Angeli, 2015; Grassi et al., 2008). Substantial variations can, furthermore, be found in the published results for holdups and flow patterns depending on the methodology applied. However, despite all the existing discrepancies between the findings in this research area, there exists a general agreement that shows the pressure drop dependency on the flow pattern and mixture velocities. This implies the significance of fluids configuration in pipes in every study of multiphase flow. In any multiphase flow system, flow pattern is a fundamental feature which characterizes the internal configuration and relative position of the phases during the flow. Generally, the classification of flow patterns starts from completely separated to fully dispersed flows. In separated flows, both of the phases retain their continuity whereas this continuity is demolished for one of the phases in dispersed flows. Perhaps one of the most comprehensive flow patterns classifications can be found in the work of Elseth (2001), covering almost all types of the flow patterns which one may observe during the flow of a model oil and water in horizontal pipes (see Fig.1). The proposed classification is listed as follows: 

Segregated flows 

Stratified smooth (SS)



Stratified wavy (SW)



Stratified mixed (SM): a) Stratified mixed (SM) with water droplets in oil b) Stratified mixed (SM) with oil droplets in water c) Dual continuous (DC)



Dispersed flows

3



Dispersion of water in oil and oil layer (Dw/o&o)



Dispersion of oil in water and water layer (Do/w&w)



Fully dispersed (FD)

Fig. 1. Oil-water flow patterns: (a) separated flows and (b) dispersed flows (Elseth, 2001).

Based on the wetting (hydrophilic or hydrophobic) characteristics of the pipe material, another important flow pattern known as core-annular flow may be established during the flow. In this flow type, one of the phases is lubricating the entire perimeter of the pipe in the form of an annular film along the pipe wall while the other phase is flowing in the core region without any contact with the pipe wall. For this flow pattern to occur, regardless of the pipe wettability, another two criteria must be satisfied – first that the two fluids must have extremely dissimilar viscosities and secondly that they must have relatively close densities (Bannwart et al., 2004). These criteria are commonly met by viscous and heavy crude oils as their viscosity is often more than 100 times greater than that of water and their density is normally close to water density. Some degrees of dispersions between the phases have also been occasionally evident, nevertheless, both of the phases retain their continuity during annular flows (Brauner, 2003). Perhaps, this fact has inspired Al-Wahaibi (2012) to categorize the annular flows as segregated flow patterns. 1.1. Influential factors on the formation and transition of flow patterns

Thus far, numerous parameters have been studied and ascribed to the formation of specific flow patterns related to the liquid-liquid two-phase flows in pipes. In the literature, pipe geometry, flow conditions and fluid properties are the main three leading factors attributed to the occurrence of and transitions between flow patterns (Fairuzov et al., 2000). Each of these factors, either directly or indirectly, makes changes to the flow structure that ultimately leads to the establishment of specific flow patterns. Table 1 lists the main factors and their associated sub-factors as well as their respective effects on the flow patterns which have been examined in the previous studies.

Table 1 Factors affecting flow patterns during oil-water two phase flow based on the previous studies.

Apart from the mentioned parameters in Table 1, the remaining variable which has been more or less ignored by the pioneer investigators is fluid composition (oil composition in particular). As for the effect of fluid compositions, however, there is no – and there cannot be a – general agreement on 4

the possible mechanisms making alterations to the flow-pattern transition boundaries due to the fluids compositions. The role of fluids compositions can be very complicated, depending on the available components. This is on account of the fact that numerous oil types with various compositions and different flow characteristics exist which all deserve to be studied individually. Nevertheless, research works done on oil-water two-phase flows have mostly been restricted to the use of model oils, i.e., synthetic or mineral oils (Cai et al., 2012; Kee et al., 2014; Tan et al., 2015), rather than crude oils. Although this practice is accepted as an attempt to improve the general knowledge on the subject, actual oil field cases may not be covered. In recent years, successful efforts have been made using viscous model oils and/or crude oils to provide data which are considered to be more representative of oilfield production conditions. The important work of Fairuzov et al. (2000), Vuong et al. (2009), Wang et al. (2011), Xu et al. (2012), Al-Wahaibi et al. (2012) and Jing et al. (2016) are just a few to be mentioned. Experimental data obtained from these works have sometimes shown new insights and revealed previously undetected phenomena or supported a new phenomenon as compared to those working on the model oils. Fairuzov et al. (2000), for instance, performed a research on the flow pattern transitions via employing sampling probes for mixture flows of a light crude oil and water in a horizontal pipeline. They observed that even in stratified flows small portions of dispersed water droplets remained within the crude oil. Kokal (2005) attributed the formation of relatively stable water-in-oil emulsions to the existence of amphiphilic molecules (molecules of having both hydrophilic and hydrophobic moieties) such as asphaltenes, resins and organic acids among the crude oil components. The existence of such molecules within crude oils makes the crudes interfacially active at the oil–water interface. During the flow of a crude oil and water, these molecules act like surfactants in lessening the interfacial tension and enhancing the tendency of the droplets of the dispersed phase to remain suspended whereby fairly stable suspensions are formed. This well explains why these molecules are often regarded as crude oils natural surfactants/emulsifiers. Pertinent studies in this regard also suggest that the stability of the crude oil emulsions are further enhanced at the presence of solid particles such as wax crystals and inorganic solid particles (Binks, 2002; Binks and Rocher, 2009; Macierzanka et al., 2009; Sullivan and Kilpatrick, 2002; Tambe and Sharma, 1993). In an attempt to investigate the differences between the flow behavior of model and crude oils, Wang et al. (2011) conducted oil/water two-phase experiments using heavy crude oil and model oil with similar viscosities. They reported a considerable difference between the obtained flow patterns at water fractions above 50%. Furthermore, unlike the model oils, w/o emulsions persistently existed in all cases and this was ascribed to the crude oil natural emulsifiers, while the occurrence of this phenomenon has never been evidenced for the cases where the model oils have been utilized. The effect of this phenomenon was strong enough on the characteristics of crude oil/water flows that Wang et al. (2011) emphasized it by including the term “emulsion” (and not dispersion) in all the proposed flow pattern nomenclatures. This implies that, an overly simplistic model oil cannot be a perfect representative of complex crude oils in terms of flow behavior. 5

The presence of wax components within crude oils is very common and often problematic. As stated by Merino-Garcia and Correra (2008), the problem with these components begins with their precipitation from the oil as semi-solid particles and later deposition along the pipe whenever temperature declines below the wax appearance temperature (WAT). At best, this phenomenon will lead to further pressure drop during fluids transportation by reducing the cross-sectional area available for flow. At worse, it clogs the pipeline and the production will be stopped for either pigging or cutting the blocked area. Despite the significance of considering these troublesome components, very little publications are available focusing on the wax components of crude oils under two-phase flow conditions (Sarica and Panacharoensawad, 2012). Moreover, most of the publications in this area provide detailed explanations regarding the mechanism(s) responsible for wax deposition and the characteristics of the deposited wax such as hardness, thickness and profile shape (Bruno et al., 2008; Chen et al., 1997; Couto et al., 2006; Hoffmann et al., 2012; Panacharoensawad, 2014; Panacharoensawad and Sarica, 2013; Shang and Sarica, 2010; Shang and Sarica, 2013). Irrespective of the occasional use of paraffinic model oils in the aforementioned works, their results are mainly restricted to specific flow patterns of stratified and dispersed flows. The most comprehensive work in this context that the authors are aware of, however, is an unpublished work by Anosike (2007) which has been cited by a number of researchers (Panacharoensawad and Sarica, 2013; Sarica and Panacharoensawad, 2012; Shang and Sarica, 2013). Using a paraffinic model oil and water in a multiphase flow loop, Anosike (2007) examined the dependency of wax deposition on various flow patterns in horizontal geometry. He ascribed the formation and deposition of the wax to the direct physical contact of the oil phase with the inner pipe wall of low temperature (lower than the WAT). Furthermore, he concluded that wax deposition is a flow-pattern-dependent phenomenon, since the relative position of the phases is controlled by the flow pattern. This finding is also consistent with that of Matzain et al. (2002) for gas-liquid systems. Besides, Anosike (2007) reported that superficial velocities of phases are responsible for the hardness and thickness of the deposits. Accordingly, an increment in either oil superficial velocity (

) or water superficial velocity (

) results in

increasing the deposit hardness and decreasing its thickness. It should be noted that the studies on paraffin deposition under two-phase flow conditions are mostly conducted using a flow loop apparatus equipped with a pipe-in-pipe heat exchanger (Sarica and Panacharoensawad, 2012). The aim is to simulate the deposition process in subsea transportation pipelines by creating a temperature gradient between flowing fluids and pipe walls. For such a purpose, the inner pipe wall temperature is kept below the WAT of the dehydrated crude oil. The main drawback of this technique for research purposes is that the formation of the wax crystals (at the wall and in the bulk) is only attributed to the induced radial temperature gradient caused by decreased temperature of the pipe wall; whereas, a new wax formation mechanism has been recently introduced by (Piroozian et al., 2016a) for water-in-waxy-crude-oil emulsion systems. According to their findings, a significant increase in the value of WAT is expected upon the existence of water in the oil 6

phase regardless of its volume. Higher WAT values were also detected at higher water volume fractions and rotational speeds through which larger numbers of droplets were formed and dispersed in the oil phase. Based on this mechanism, emulsified water droplets within waxy crude oils can locally alter the thermodynamic behavior of the adjacent surrounding portion of the crude oil and provide crystal nucleation sites. This leads to unexpectedly earlier wax crystallization while the bulk temperature is still above the WAT of the dehydrated oil. The validity of this effect on the WAT and subsequent wax formation and deposition under dynamic flow conditions is still unknown. However, the assessment of this mechanism is not feasible by employing the conventional flow loop design for paraffin deposition studies and it requires a new experimental approach. Unlike previous studies, both the pipe wall and the mixture temperatures need to be maintained almost the same and slightly higher than the WAT of the crude oil so that the formation and deposition phenomenon via the effect of radial temperature gradient can be eliminated. To this end, this study aims first to experimentally investigate the flow patterns of waxy crude oil-water two-phase flows in a designed horizontal multiphase flow loop at a temperature of 28°C which is 4°C higher than the WAT of the crude oil (24°C). Second, it aims to propose a new flow-pattern map based on the flow visualization results, and to discuss theoretically the controlling agents in the formation of such flow patterns; and finally to evaluate the authenticity of the proposed wax deposition mechanism by Piroozian et al. (2016a) in dynamic conditions.

2. Experimental setup 2.1. Working fluids

The crude oil used in the experiment was a typical Malaysian waxy crude oil obtained from Terengganu Crude Oil Terminal (TCOT), located on the East Coast of Peninsular Malaysia. The crude oil is categorized as a dead crude oil with a carbon number of minimum eight recognized by gas chromatography–mass spectrometry (see Table 1 in the Supporting Information). Table 2 presents the physical properties of the crude oil measured in Universiti Teknologi Malaysia's ISO 17025 accredited laboratory (UNIPEM) according to standard methods. For the aqueous phase, tap water with density of 998.2 kg/m3 and viscosity of 1.003 mPa.s at 25 °C was used. Fluorescent dye was added to the water to improve the visualization of dispersed water droplets in the opaque crude oil medium.

Table 2 Physical properties of waxy crude oil used in this study.

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2.2. Test facility

A flow test facility was designed, constructed and commissioned at the Malaysia Petroleum Resources Corporation Institute for Oil and Gas (UTM-MPRC Institute for Oil and Gas), Universiti Teknologi Malaysia (UTM). The facility is capable of simulating single or two phase flow of oil and water in a horizontal pipe section. Fig. 2 illustrates the schematic diagram of the oil-water experimental setup.

Fig. 2. Schematic diagram of the flow loop facility: 1. oil tank, 2. oil bypass line, 3. transmitter and receiver, 4. ultrasonic flow meter, 5. water tank, 6. water bypass line, 7. copper tubes, 8. mezzanine platform, 9. centrifugal pump, 10. ball valve, 11. Y mixing point, 12. flange, 13. pressure transducer, 14. mixture line, 15. camera/video recorder, 16. view box, 17. black light fluorescent tube, 18. air compressor, 19. transparent acrylic pipe, 20. pneumatic quick closing valve, 21. drainage line, 22. graduated beaker, 23. temperature transducer, 24. oil/water separator, 25. water return line, 26. oil return line, 27. chiller, 28. computer, 29. National Instrument (NI) data acquisition system, 30. linking wire and 31. digital temperature meter.

The flow rig consists of five main segments, namely feeding, test, separation, replenishment and cooling sections. First segment comprises oil and water tanks of volume 0.2

each, two 2-HP

centrifugal pumps (having a maximum speed of 2900 rpm and capacity of 42

and a modified

‘Y’ mixing point. The modification allows the two fluids to be joined in a 30 ◦ Y-junction. Further deviation of the right inlet of the Y-junction from the horizontal plane by θ = –10° allows the water phase entering mixture line from the bottom (Fig. 3). This modification was arrived as per the industrial experience which could facilitate the flow with a smoother introduction of the phases at the mixing point and therefore mitigating the entrance effect.

Fig.3. Schematic diagram of oil–water mixing point. (angles indicated are in degrees)

The mixture line, which is started from the mixing point, is extended to the test section by an 8.38-m straight commercial carbon steel pipe (ID: 38.1 mm) known as one of the most commonly used pipe materials in petroleum transportation (dos Santos et al., 2006). This gives the ratio of the entrance length to the diameter of 220 which is, based on the literature, sufficient for the stabilized

8

flow to be developed along the pipe. This is followed by a 2.36-m long transparent acrylic pipe (ID: 38.1 mm) as the test section which enables the optical access to the two-phase flow pattern. Two quick closing ball valves with pneumatic actuators (WATTS PA180M2) were installed at both ends of the acrylic pipe to trap the mixture fluids for free-water measurement. The test section is, then, connected to an oil/water separator via another carbon steel pipe with length of 4.75 m of the same diameter. The separator is specially designed to deal with serious w/o emulsions and gelled waxy oils. Regrettably, to successfully redissolve solid wax, proper heat-treatment techniques are required which are all time-consuming and costly. In addition, more time is needed to cool down the hot separated water-free oil to reach the test temperature. Therefore, separation can only take place after completion of each run since instantaneous breaking the emulsions and redissolving crystallized wax into the crude oil is not feasible on laboratory scale experiments. By considering all the aspects, the separator is divided into three main segments: (1) accumulative tank (maximum capacity of 1.9 m3), (2) reserve water tank (maximum capacity of 0.5 m3), and (3) reserve oil tank (maximum capacity of 0.76 m3). The used fluids are discharged into the accumulative tank which is equipped with a liquid-liquid coalescer (HCF plate-pack type by Fabco Inc.) and three oil immersion heating elements (flange-type with maximum power output of 15-12 w/in2 by Durex Inc.). The water enters the reserve water tank section through a 2-cm gap under the partition between the accumulative and reserve water tanks. This water can be the free (unadulterated) water during the experiment or the separated water after the separation. The reserve water tank comprises an outlet having an adjustable bend which is capable of being rotated so that the level of the water in the separator can be adjusted in the time of need. The separated oil, however, overflows into the reserve oil tank only after the completion of the separation. After each test, the entering oil/water mixture undergoes a period of retention up to 45 minutes in a closed system. The fluids are meanwhile heated up to as high as 80 °C by the heating elements to mainly redissolve wax crystals and increase the settlement rate of the emulsified water droplets. These conditions yield a separator efficiency of 95-97 %. The reserve oil and water tanks are remote supplementary tanks to simultaneously replenish the main upstream tanks with fresh fluids for maximum seven minutes with superficial velocities of 1 m/s. A centrifugal pump (with the same specifications as the inlet pumps) and a return line are provided for each of the tanks to feed the replenishment system. As the last section, a combination of industrial water chiller (Model: SP30; cooling capacity of 3020 kca/hr) and spiral copper tubes (located inside the water tank) are used as the cooling section. In this system the mixture temperature is maintained by controlling the water temperature. This is based on the proposed method by Piroozian et al. (2016b). In this regard, mixture temperature is, first, predicted by knowing the temperature of the fluids in their respective tanks. The test is allowed to be run only if the difference between the predicted and predetermined temperature values is less than 0.5 °C. However, if expectations are far reached, a new water temperature is set and the procedure is 9

repeated until this criteria is met. Fig. 4shows the schematic configuration of the designed oil/water separator.

Fig. 4. Oil/water separator.

In conjunction with the main segments, some auxiliary instruments are also installed to facilitate data acquisition process during the experiments. Among them, the most important items relevant to the objectives of this study are thermocouples and flow meters. Accordingly, four thermocouple probes (type HT-1; accuracy: ±0.1 °C from 0 to 50 °C) connected to temperature indicators (TPM-900) which were used to display the detected mixture temperatures with an accuracy of ± 0.5 °C and resolution of 0.1 °C. The flow rates can be measured with high accuracy of 1 % using individual ultrasonic flow meters (TUF-2000H-TM 1- 5) which are placed one meter downstream of the pumps. It is also noteworthy to mention that the pipeline was properly wrapped with fiberglass heat sealing tape (model no: FD-EG106-R) for thermal insulation and energy conservation.

2.3. Wetting characteristics

The wetting behavior of the experimental liquids (waxy crude oil and water) at the surface of the pipes were examined via contact angle measurement. Sessile-drop technique was applied for the measurement in a way that a drop of the oil was carefully placed, by means of a syringe, on the inner surface of the pipe specimens which were immersed into the aqueous phase. Thereafter, photographs of the droplets were captured using a digital camera (12.3 MP, D90, Nikon) and the angles were analyzed using an image processing software (Digimizer version 4.2). Fig. 5 shows the oil droplets on the surface of acrylic and carbon steel pipes. The contact angles of

> 90° for the oil droplets attest

to the hydrophobic surface characteristics of the both pipes.

Fig. 5. Illustrations of the measured contact angles on inner pipe surfaces: (a) acrylic and (b) carbon steel.

2.4. Flow pattern observation

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The flow pattern identification was done via visual observation and free water measurement for oil and water superficial velocities ranging from 0.1 m/s to 0.7 m/s and 0.1 m/s to 1.0 m/s, respectively. The visual identification of flow patterns under a wide range of flow conditions was carried out by photography (including front-, bottom- and side-view photography) and video capturing. Besides, the test section was equipped with a rectangular transparent box (visual box) filled with glycerine for provision of a better sight. The combination of an acrylic window and glycerine minimizes the curvature effect of the pipe which improves the detection of liquids levels. A highspeed camcorder (shutter speed 1/8-1/10000 s, 30x optical zoom, 8.9 MP, HDR-PJ260VE, Sony) together with a high-definition digital camera (shutter speed 1/4000 s, 5.8x optical zoom, 12.3 MP, D90, Nikon) were placed at a 50-cm distance from the visual box. Meanwhile, an auxiliary digital camera (shutter speed 1/4000 s, 15x optical zoom, 8 MP, Cybershot DSC-H9, Sony) was used to produce side shots from different angles of the test section during flow pattern observation. The main purpose of measuring free water was to distinguish partial from fully emulsified water during the flow. Fortunately, the persistence of the waxy crude oil to retain the entered water droplets hindered gravity segregation and provided the opportunity to measure the remained free water even after shutting down the flow. This measurement was made after a steady-state condition was achieved and flow pattern was identified under a given flow condition. In this process, a fixed volume of the mixture (3 L) was trapped in the test line by simultaneously closing the quick closing valves. The line was, then, drained off into a 5-L graduated beaker after two drainage steps. As the initial drainage, the fluids were discharged by gravity for about 20 minutes to ensure the exit of the whole free water from the test line. Thereafter, the volume of the free water was simply measured via its level in the graduated beaker. Unlike the water, some portion of the oil remained in the test line regardless of the elapsed time. This was because of the crude oil being contaminated with w/o emulsion which resulted in a higher viscous fluid that needed extra energy to flow. Therefore, after measuring the free water, the test section was washed off, as the secondary drainage, using hot water of 80 °C and the fluids were collected for further measurements.

3. Results and discussion

3.1. Flow-pattern determination

A total of 70 tests were conducted to experimentally investigate the flow patterns for waxy crude oil-water in a horizontal two-phase flow system at 28 °C. The tests were performed for oil and water superficial velocities in a range of 0.1 to 0.7 m/s and 0.1 to 1.0 m/s, respectively, while the bulk fluid temperature was relatively (≤ 0.5 °C) cooler than the pipe wall. As highlighted in the methodology, the flow pattern identification was done via visual observation and free water 11

measurement. Based on the visual observation, it was noticed that despite maintaining the temperature of the both phases and inner pipe wall surface above the WAT of the dehydrated crude oil throughout the tests, there was still wax deposition for some of the flow conditions. The unexpected presence of wax crystals at a temperature above the initial crude oil WAT is explained by considering the effect of emulsified water on the WAT of water-in-waxy-crude-oil emulsions as reported by Piroozian et al. (2016a). By considering this phenomenon, nine flow patterns were identified and grouped under two main flow categories:

a. Fluids flow without wax deposition 

Stratified flow with partial emulsion of water in oil at interface (ST-PE)



Stratified wavy flow with partial emulsion of water in oil at interface (SW-PE)



Dual continuous flow (DC)

b. Fluids flow with wax deposition



Wax deposit and dual continuous flow (WDC)



Wax deposit and eccentric annular flow with partial emulsion of water in oil at interface (WEA-PE)



Wax deposit and eccentric annular flow with full emulsion of water in oil (WEA-E)



Wax deposit and eccentric annular flow of dual continuous (WEA-DC)



Wax deposit and fine dispersion of oil in water with thin layer of oil at the top of the pipe (WFDo/w-TLo)



Wax deposit and fine dispersion of oil in water with streaks of oil at the pipe wall (WFDo/w-So)

Fig. 6 demonstrates a representative schematic cross-sectional view of each test condition.

Fig. 6. Flow pattern classification for waxy crude oil-water in a horizontal two-phase flow system at 28 °C and WAT of 24 °C: (a) ST-PE, (b) SW-PE, (c) DC, (d) WDC, (e) WEA-PE, (f) WEA-E, (g) WEA-DC, (h) WFDo/w-TLo and (i) WFDo/w-So.

As a complement, an original flow-pattern map was also developed that pertains to the mixture flow of waxy crude oil and water in a horizontal pipe system at a temperature slightly above the WAT. Fig. 7 shows the flow-pattern map with superficial velocity coordinates.

Fig. 7. Experimental flow-pattern map for the current study. 12

3.1.1. Fluids Flow without Wax Deposition

The following flow patterns represent the cross-sectional configuration of the oil and water phases found under the flow conditions where there was no tangible evidence for the deposition of solid wax particles on the pipe wall after maximum six minutes of oil-water concurrent flow. However, based on the findings of Piroozian et al. (2016a) and our observations, it was believed that wax crystals were formed and participated in the formation of w/o emulsions wherever water droplets entered the oil layer. The generated wax thereupon started to grow in the bulk oil. Here, the bulk oil refers to the entire oil phase including the emulsified and non-emulsified (unadulterated) parts of the oil. Our speculation of growing the generated wax in the emulsified part, and later reaching to the unadulterated part is based on the inherent nature of wax crystals immediately after their emergence. The general knowledge regarding the wax crystals is that the deposited wax crystals have a tendency to grow, aggregate, and eventually form a highly porous three-dimensional structure which entraps the liquid oil to form oil gel. In case of w/o emulsions, wax crystals adsorb onto the surface of water droplets, and continuously

grow to an extended network whereby dispersed water and oil are

entrapped and finally the system spans the entire volume and the gelation is completed (Li et al., 2014; Visintin et al., 2008). Nevertheless, further in-depth study is suggested to further evaluate our findings in both flow experiments and static cooling experiments of w/o emulsion/crude oil in order to find out the mechanism(s) responsible for wax deposition on the part in contact with the unadulterated layer of the crude oil which is discussed later in this study. Nevertheless, these wax crystals did not find the chance to reach the pipe wall since the crystal growth, diffusion velocity and the time were insufficient at lower mixture velocities. Below are the characteristics of such flow patterns:

1. Stratified flow with partial emulsion of water in oil at interface (ST-PE): This type of flow was found to have appeared once, at the mixture velocity of 0.2 m/s as the oil and water entered into the system with the same superficial velocity of 0.1 m/s. In this configuration, the oil phase was overlying the water phase with an explicit interface. After pipeline shutdown, a small portion of water was found entangled in the form of droplets within the oil phase near the interface. The presence of water droplets into oil at this mixture velocity is not a common occurrence during concurrent flow of model oils and water since the velocity is not high enough to create conditions for the onset of one phase entrainment into another. However, the occurrence of this phenomenon in this study is attributed to the entrance effect and natural surfactants found among the crude oil components. The crude oil and water underwent an inevitable extra agitation at the mixing point 13

whereby the phases were partially entered into one another in the form of droplets. As the flow was developed along the pipeline, the dispersed droplets had tendency to return back to their respective phases due to gravity and buoyancy forces. At this point, the dispersed water droplets were trapped in the oil phase by the existing bipolar components (the natural surfactants) within the crude, generating a layer of stabilized water-in-oil (w/o) emulsion in the vicinity of the oil/water interface. It is quite plausible that emulsion stability was partially related to the presence of unexpectedly formed wax crystals as a result of elevated WAT of the crude oil surrounding the water droplets. A similar phenomenon was experienced for all flow conditions, since a layer of w/o emulsion was observed for all types of flow patterns found in this study. This finding is consistent with findings by Fairuzov et al. (2000), Kokal (2005) and Wang et al. (2011). 2. Stratified wavy flow with partial emulsion of water in oil at interface (SW-PE): This flow pattern appeared right after the ST-PE as

was raised to a maximum of 0.5 m/s while

was kept

under 0.3 m/s. The increment of the mixture velocity brought about the formation of waves and generation of more outward forces from both phases on the interface. The interfacial force meanwhile acted to hold the interface intact. Therefore, instead of rupturing the interface due to the velocity difference between the phases, the water phase showed a convex interface in relation to the oil phase while flowing in the oil-wet pipe. As highlighted by Lim and Huang (2006), the orientation of the curvature formed at the interface between two fluids indicates the direction at which the interfacial force acts. This interfacial behavior is ascribed to the relative wetting tendencies of the two fluids with the wall surface. The curvature is shaped as such that the fluid with stronger affinity for the solid surface is on the concave side of the interface while the fluid with weaker affinity for the solid surface is on the convex side. Fig. 8 illustrates the curvature occurred at the interface which is perceptible by comparing the height of the oil at motion with its height at rest (see also the video in the Supporting Information). The residual of heavier components of the oil on the pipe surface is also notable after releasing the mechanical stress from the fluids and enclosing them at rest. Such a tendency of the oil components to wet and cover the pipe surface was observed for all flow conditions which affirms the oleophilic characteristic of the pipe.

Fig. 8. The interface shapes responsible for the height of the oil phase: (a) at motion and (b) at rest.

3. Dual continuous flow (DC): At low oil superficial velocities ( water superficial velocities (0.3

0.3 m/s) and moderate

0.7 m/s) both phases still remained continuous similar to

SW-PE; however, the tiny droplets of both phases were present in the opposite phase near the interface. This happened since the interfacial force was attenuated by higher relative movements of the two fluids. In other words, the discrepancy in the velocity of the phases had reached the point 14

where the wave amplitude at the interface was at its maximum and droplet detachment from the slower phase by the faster phase was probable. Fig. 9 illustrates the dented edges of the oil layer at the interface owing to the created suction pressure forces below and above the interface as a result of such velocity differences. The interface was further disrupted by the viscous force exerted, arising from the disparity between the viscosity of the phases which also paved the way for the droplets of the faster phase to be dispersed in the slower phase close to the interface. At higher oil velocities ( 0.2 m/s), the growth in the thickness of the oil layer was associated with greater outward force on the interface. Consequently, the extension of the oil phase on the concave side of the interface was accelerated proportional to the resultant interfacial force. Therefore, the interfacial energy was faster compensated for resisting the induced deformation force which explains the faster emergence of DC at lower water velocities and higher oil velocities.

Fig. 9. Laceration of the interface as the momentum and viscous forces prevailed over the interfacial force during transformation of flow from SW-PE into DC. = 0.2 m/s & = 0.7 m/s.

3.1.2. Fluids Flow with Wax Deposition

The identified flow patterns were also extended to the cases where the population of the emerged wax crystals had reached a point at which wax deposition on the pipe surface became feasible. The recognition of these solid particles was simply possible by considering their remaining track on the pipe inner wall after trapping and discharging the fluids for holdup measurement purposes. Some examples of such wax depositions on the pipe wall after initial drainage of the trapped fluids are displayed in Fig 10.

Fig. 10. Recognition of wax deposit via visual inspection of residual oil components on the pipe wall after initial drainage of the trapped fluids within the transparent pipe for different flow conditions: (a) no tangible wax precipitation on the pipe wall, (b) wax sediment on the top side of the pipe.

In the following paragraphs each of these flow patterns is briefly discussed:

4. Wax deposit and dual continuous flow (WDC): This flow pattern is comparable to the DC flow in terms of the configuration of the phases. However, the difference arises from the fact that

15

increasing mixture velocity was followed by the exacerbation of the interface instability. This results in further dispersion of water droplets into the oil as the oil phase became the dominant phase. The entrance of a larger numbers of water droplets into the oil phase intensified the wax nucleation and distribution in the oil layer. Likewise, the radial diffusion and rate of wax crystal growth were enhanced throughout the bulk oil in such a way that they permeated to the upper layers of the oil closer to the pipe surface and began to deposit. For lower oil velocities, where the water was the dominant phase, the mechanism was quite different. In a water-dominant flow, the oil phase was undercut at the interface and dwindled to a lower level which in return shortened the path for the appeared wax crystals particularly near the interface to grow and reach the pipe surface. As a result, a continuous growing layer of wax was formed, covering the pipe wall where the oil phase was in contact with. 5. Wax deposit and eccentric annular flow with partial emulsion of water in oil at interface (WEA-PE): The tendency of the oil to cover the entire inner pipe surface eventually resulted in annular flow beginning at oil and water superficial velocities of 0.4 and 0.1 m/s respectively. This flow pattern became evident at moderate oil superficial velocities ( water superficial velocities (

0.5 m/s) and low

0.2 m/s) as a transient pattern from either SW-PE or WDC to

eccentric annular flow with full emulsion of water in oil (EA-FEw/o). The distinction between the partial emulsion and fully emulsion of water in oil was recognizable only after cutting off the flow and measuring the free water as shown in Fig. 11c. At stationary condition (Fig. 11b), the phases returned to their gravitationally favored locations where the deposited water phase was seen in darkish-green color as a result of pipe contamination with the oil, indicating once again the coverage of the pipe with the oil phase during fluid flow (Fig. 11a). Theoretically, the interface seemed to be stretched out proportional to the summation of momentum and viscous forces acting on the interface during the course of evolution from ST-PE to WEA-PE. This phenomenon is pertinent to the reciprocal response of the interfacial force to negate the influence of such forces. Consequently, the interface attained a curved configuration whose direction is imputed to the solid-fluid wettability as declared by Brauner et al. (1998).

Fig. 11. Image of fluids (a) at motion, (b) at rest and (c) after drainage for free water measurement. = 0.5 m/s & = 0.1 m/s.

6. Wax deposit and eccentric annular flow with full emulsion of water in oil (WEA-E): At high oil superficial velocities ( (0.1

0.5 m/s) and for low to moderate water superficial velocities

≤ 0.6 m/s), there was no free water layer formed as the total water content was emulsified.

The full dispersion of water was characterized based on the absence of free water during holdup 16

measurement (Fig. 12). The full coverage of the pipe by the oil phase was again perceptible during the flow while water-in-oil emulsion is presumed to be passing through the confined channel relatively close to the bottom of the pipe. Such a presumption was firstly based on the limitation found in the distribution of water droplets into the upper layers of the oil in oil-dominated flows. This is attributed to the entrapment of the water droplets upon their entrance into the lower layers of the oil by the existing bipolar components and later by the formation of wax crystal network around the trapped water droplets. Subsequently, a water-free oil layer was formed at the top of the pipe. Secondly, the assumption was made owing to the higher density of the formed w/o emulsion compared to the remained water–free oil layer. Consequently, the emulsion part seemed to have been enclosed between a thin layer of the oil from bottom and a thicker oil layer at its top. Despite the coverage of the entire inner pipe surface with the oil, wax deposition was exclusively identifiable at the part which was in contact with the thicker oil layer (at the top of the pipe). This was due to the low concentration of heavy paraffinic components within the thin oil layer which made it almost impossible for the wax crystals to accumulate on the lower side of the pipe. Even though the deposition of these components was plausible at the bottom of the pipe because of their vicinity to the wall, they had to undergo the drag force by the adjacent flowing fluid upon settling on the pipe surface, creating a predominantly lean trace of wax deposition. Apart from this, wax crystals adjacent to the water droplets had a tendency to participate in further stabilizing the w/o emulsion by aggregating on the surface of water droplets rather than agglomerating on the wall surface. This was deduced from the fact that the predetermined operating temperature (28 °C) was always slightly lower than the ambient temperature (approximately 29 °C) and there was a heat gain of less than 0.3 °C along the pipeline despite the pipe isolation. In other words, the inner pipe surface could not be cooler than the flowing fluids owing to the heat gain from its surroundings under the influence of the warmer ambient temperature. Such a temperature gradient implies that the wax crystals prefer being involved in the cooler medium rather than being deposited on the warmer pipe circumference.

Fig. 12. Characterization of fully dispersed water in the absence of free water during the measurements. = 0.6 m/s & = 0.3 m/s.

7. Wax deposit and eccentric annular flow of dual continuous (WEA-DC): The slight increment in the water cut, at the point of transition from WDC, enhanced the outward force from the water phase toward the interface to occupy more space. Nevertheless, this force was not adequate for full disintegration of the interface. Instead, the resultant interfacial force acted to further stretch the oil phase on the concave side of the interface so that the water phase on the convex side is displaced. This made the oil layer to be extended throughout the pipe surface while the rest of the flow was

17

maintained as in WDC. Meanwhile, the slight increase in the water cut at the point of transition from WEA-E (as long as

was greater than 0.6 m/s) caused the formation of larger droplets. This in turn

improved the chance of the adjacent droplets to coalesce into larger ones. Eventually, the water phase partially regained its continuity following the random collision of such droplets. 8. Wax deposit and fine dispersion of oil in water with thin layer of oil at the top of the pipe (WFDo/w-TLo): This flow pattern was observed after feeding the system with m/s and

greater than 0.7

less than 0.4 m/s. Under these circumstances, water was the dominant phase and the oil

phase was undercut at the interface by the water. Moreover, the interface was totally disintegrated and the oil layer was getting shrunk as droplets of oil were detached and dispersed into the water phase. Accordingly, the height of the water phase rose to wet more of the pipe perimeter (Figs. 13a and 13b). However, the full coverage of the pipe with the water phase was not observed even at the highest (1.0 m/s) and a thin layer of oil with wax deposit over it remained at the top of the pipe (Fig. 13c).

Fig. 13. Front and side view photos of water growth on the pipe wall as water superficial velocity increased for a constant oil superficial velocity during WFDo/w-TLo flow.

In spite of velocity superiority of the water phase over the oil phase, a small portion of water was again found entrapped within the oil near the interface which became visible after ceasing the flow (Fig. 14). This affirms the authenticity of the considered mechanism for the formation of wax.

Fig. 14. Presence of the w/o emulsion at the interface during shutdown period and after natural segregation of the phases. = 0.2 m/s & = 0.8 m/s.

9. Wax deposit and fine dispersion of oil in water with streaks of oil at the pipe wall (WFDo/w-So): This flow pattern emerged right after WEA-DC as a response to the further increase in to 1.0 m/s. Water was indisputably the dominant phase and fine dispersion of oil droplets were thoroughly and vigorously distributed throughout the water phase. The form of the flow pattern on the pipe wall, however, resembled a snake-skin pattern in which the thin oil layer coating the whole pipe perimeter became patchy and dragged by the continuous water phase (Fig. 15).

Fig. 15. The flow of oil and water on the pipe wall in the form of the snake-skin pattern during WFDo/w-So.

= 0.5 m/s &

= 1.0 m/s.

18

For future studies, further evaluation of the identified flow patterns is also recommended to be accomplished through the use of conductivity probes, gamma ray densitometry or any other available techniques to improve the certainty.

3.2. Relationship between oil-water flow and wax deposition

Under the flow conditions of this study, the wax deposition was found to be flow-patterndependent. This is in agreement with the reports by both Anosike (2007) and Matzain et al. (2002) who declared different wax deposition characteristics for different flow patterns (see Table 2 in the Supporting Information for details). The results of the current study, however, showed no considerable diversity in the configuration of the deposited wax, and the deposition was exclusive to the top of the pipe wall where the crude oil was in direct contact with the solid wall. Three factors are to be blamed for such inconsistency between the current study and the previous ones. First, the short period of time (6 minutes) dedicated to complete each run in this study did not allow for the sufficient accumulation of wax on the bottom of the pipe where only a thin oil layer and/or lower concentration of oil droplets were available. Accordingly, no wax layer could be formed at this section. In contrast, in the works of Anosike and Matzain, the authors dedicated adequate time (24 hrs) for the deposition and growth of wax crystals since their aim was to investigate the formation of wax deposit with flow pattern over time. The second factor is pertinent to the opposite direction of temperature gradient in this study as compared to the aforementioned studies. Temperature gradient is known as the thermal driving force which enhances the rate of wax deposition in favor of the cooler part of the system. As the present experiments were conducted in an operating temperature below ambient temperature, the pipe surface was expected to be relatively warmer than the bulk fluid. It was due to the heat transfer of the pipe surface with the warmer surroundings despite the insulation provided by the pipe wrapping. Hence, the temperature gradient was no longer effective as a deposition-promoting factor and this, in return, induced the wax crystals to stay within the bulk fluid rather than being deposited on the pipe wall particularly at the bottom section where wax crystals were scarce. The third factor arises from the division between the operating temperature of the current and previous studies. In all oil-water paraffin studies, the temperature was kept below the WAT of the dehydrated crude oil through which wax crystallization process was accelerated.

The temperature in this study, on the

contrary, was maintained above the WAT of the oil which decelerated the precipitation of wax components during the course of the experiments. Although this study was not specifically designed to assess the quality of the wax deposit, it was evident that the thickness of the deposited wax layer was subordinate to the superficial velocities 19

of the fluids over the fixed time of the experiments. Fig. 16 illustrates such a relationship between the wax thickness and the superficial velocities of the phases. The thicker wax deposits was formed at higher water superficial velocities for a constant oil superficial velocity. This can be explained by the mechanisms which came to pass naturally in succession, during the interface breakdown. In the early stages of the interface breakdown via the faster phase (water), the trapped water droplets were released and the gelled oil around these water droplets was interspersed into the water phase as small chunks of gelled oil or semi-solid-oil droplets (with varying solid-wax fractions). This was followed by further reconstruction of a new layer of w/o emulsion at the interface, decomposition of the new emulsion layer, extrication of newly trapped water droplets and dispersion of the gelled oil around the water droplets in the water phase. These steps were constantly repeated as the water level was elevated subsequent to the rise of

. Therefore, more layers of the oil phase had to undergo the

emulsification and disintegration processes at higher

which provoked the formation of more wax

crystals and semi-solid-oil droplets. The detached oil droplets were carried within the turbulent water flow and stuck to the pipe surface upon their contact with the pipe. However, the oil droplets had a higher tendency to occupy the upper part of the pipe as compared to water at the bottom under the influence of buoyancy. Hence, they mainly deposited at the top of the pipe or stuck to the prior deposited wax layer(s) to make it thicker rather than attaching to the sides of the inner pipe surface and being sheared off by the flowing fluids. It is also noteworthy to mention that, no substantial wax growth was sensed for

0.7 m/s. This is also supported by the results of the study conducted by

Couto (2004), which reveal that the deposit wax fraction increases with water cut up to 60% and then stays about the same. Fig. 16 also illustrates the development of the wax thickness with increasing oil superficial velocity at a constant water superficial velocity. This is owing to the fact that more wax components were available by introducing more oil into the system. Accordingly, thicker wax deposit at higher oil superficial velocities for the same water superficial velocity is self–explanatory and unambiguous. As for wax rigidity, however, harder wax deposition was realized at lower oil velocities and higher water velocities. This can be explained by the fact that at lower oil velocities, less wax particles were present in the flow and more of the soft wax deposition was scoured by the flowing water phase.

Fig. 16. Relationship between the wax thickness and the superficial velocities of the phases: (a) , (b) , (c) and (d) . (Photos have been taken during pipe drainage after the completion of each run)

In summary, the results of the present study indicate the authenticity of the proposed new parameter by Piroozian et al. (2016a) for the formation and deposition of wax crystals during waxy 20

crude oil-water mixture flows. Moreover, an original flow pattern map has been developed based on a number of new flow patterns observed in this study; however, no comprehensive comparison can be made with the available maps in the open literature. This is mainly due to the combination of the two specific types of parameters we have included to investigate the flow patterns. The first type was to provide conditions relatively similar to the oil field case by using an actual crude oil and the commonly used carbon steel pipe for oil and water transportation. The second type was to make it feasible to examine the newly proposed mechanism for the wax formation during the flow by means of keeping the pipe wall slightly warmer than the bulk fluids and operating the system in a slightly higher temperature than its WAT.

3.3. Response of pressure gradient to flow patterns

The results of pressure gradients for different mixture velocities have been plotted against input water fractions in Figs. 17 and 18. For each mixture velocity the input water faction was varied from 10% to 90% or as much as it was allowed within the restrictions given by the capacity of the system to supply the crude oil. In general, a fall in pressure gradient can be noted right before flow pattern transition from annular to either segregated or dispersed flows. This phenomenon is attributed to the velocity and viscosity of the phase or phases in contact with the pipe wall. According to the conclusion of Bannwart (2001), the correspondent pressure drop during annular flow is comparable to the single-phase flow of the lubricating phase (either water or oil) with the same total volumetric flow rate. In other words, the effective viscosity of the oil-water mixture is largely dependent on the viscosity of the external phase during the annular flow. In this study, the oil was the lubricating phase flowing at the pipe wall in any type of annular flows. Therefore, the decline in pressure gradient during the annular flow is justified for a constant mixture velocity as the water cut is increased up to a limit and the actual oil velocity is proportionally decreased; and such response is perceptible through the oil holdup and slip ratio results given later in section 3.4. This result is in a good agreement with the findings of Lovick and Angeli (2004) regarding the trend of the pressure gradient during annular flows. Any further increment in water cut, however, brings the two phases into contact with the pipe wall right after the transition which causes a jump in the pressure drop by providing more turbulent flow as both fluids’ velocities and viscosities come into account. For low mixture velocities (0.5 – 0.8 m/s), this transition occurs at low water cuts in a range of 0.17 – 0.28. Moreover, no inversion point is detected for mixture velocities up to 0.8 m/s since there is no finely dispersed o/w flow pattern under such circumstances.

Fig. 17. Pressure gradient in oil/water flow – low mixture velocities. 21

Fig. 18. Pressure gradient in oil/water flow – moderate to high mixture velocities.

The same trend is evident from Fig. 18 for moderate mixture velocities (0.9 – 1.0 m/s) during the flow pattern transition from WEA-DC to WDC. Despite observing oil-dominant and then waterdominant dispersed flows at lower and higher water cuts, respectively, the phase inversion point does not emerge in the figure for such mixture velocities. This is due to the occurrence of an intermediary flow pattern (WDC and/or DC) which overshadows the peak in the pressure gradient during phase inversion leading to an almost step change condition. The phase inversion phenomenon from oil continuous to water continuous appears clearly and without any ambiguity only at mixture velocity of 1.1 m/s and 73% water cut. This is in disagreement with the mostly reported value of the water cut (around 35%) responsible for the phase inversion. The delay in reaching the inversion point is partly because of the entrapment of the dispersed water droplets by the natural surfactants and further by the solid wax network of fine crystals within the crude oil and partly because of the oil-wet characteristic of the inner surface of the pipe. In the former case, the trapped water droplets can hardly coalesce into a continuous water phase and for doing so high concentration of large droplets are required. The latter case causes the lag in the emergence of the phase inversion as the entire inner pipe wall is inherently lubricated by a thin oil film even in the cases where water is the continuous phase. To overcome such a consistency of the crude oil for wetting the pipe, higher scouring ability of the water phase is essential which is not possible, except for higher water superficial velocities at higher water volume fractions. For high mixture velocities (

1.2 m/s), the existence of WFDo/wSo flow as a newly

found flow pattern attenuates the effect of phase inversion on pressure gradient. WFDo/wSo flow which appears as a transition between WEA-DC and WFDo/w-TLo displays a dual flow characteristic. At lower water cuts where more part of the pipe wall is wetted with the oil, the flow behavior is almost similar to the annular flow. This behavior gradually shifts to dispersed flow with increasing water cut percentage as a result of enhancing the scouring capability of the water phase to wash out the remaining oil layer on the pipe wall. In response to this flow behavior change, the pressure drop initially drops to its minimum magnitude and then starts to elevate steadily with a moderate slope. From Figs.17 and 18, it is also evident that the minimum value of pressure gradient appears in the region of annular (WEA-DC, WEA-E, WEA-PE when semi annular (WFDo/wSo when

< 1.2 m/s except one case

≥ 1.2 m/s), or DC (for the case of

=1.1 m/s),

=1.1 m/s) flow patterns. By

implication, this means that the minimum in pressure gradient emerges at a water volume fraction where the inner pipe is completely or largely wetted by the oil phase and the actual oil velocity has 22

reached its minimum value. Similarly, Lovick and Angeli (2004) found the minimum in pressure gradient to appear under a transitional pattern where the oil occupied either all or a large part of the pipe and there existed a high concentration of dispersed water as part of the flow. For such conditions, they claimed that drop breakup and coalescence were responsible for the dissipation of the velocity turbulence of the oil phase which, in returns, led to a great reduction in the pressure gradient. This phenomenon is called drag reduction which, in turn, led to a great reduction in the pressure gradient. In our study, however, it is believed that the reduction in the pressure gradient due to the drag reduction was further intensified by the decline in the oil actual velocity during the annular flows for a constant mixture velocity as the water cut increased up to a limit. In summary, it can be concluded that pressure drop in waxy-crude-oil/water flows is dependent on mixture velocity, input water fraction, flow pattern and the parameters that flow pattern is a function of (such as pipe wettability, superficial velocities and oil composition).

3.4. Oil holdup

The data obtained for the in-situ volume fractions or holdups (H) of the phases can be compared with their respective input volume fractions (λ) to recognize the existence of any slippage between the phases. To that end, Fig. 19 presents input oil volume fraction (λo) against oil holdup (Ho). As can be seen, the majority of data (about 97%) are either above or below the identity line (solid red line) with positive/negative maximum deviation of +10% and -40%, respectively. This affirms the discrepancy between Ho and λo which, by implication, reveals the existence of the slippage between the two phases. Therefore, the assumption of homogeneity is violated in case of waxy-crudeoil/water two phase flows. For Ho ≥ λo, the majority of the flow patterns was identified as different types of stratified, dual continuous and annular flows under which the oil phase was in contact with either the whole or greater part of the pipe perimeter due to the preferential wetting characteristics of the wall. However, by further increasing mixture velocity, transition of flow patterns into FDo/w, where water is the dominant flow and mostly in contact with the pipe wall, has resulted in Ho > λo and Ho < λo for WFDo/w-TLo and WFDo/w-So flows, respectively. In the course of WFDo/w-TLo flows, it is believed that the flow turbulence was not sufficient enough to homogeneously disperse the oil droplets and thus dense concentration of oil droplets were formed at the upper part of the pipe moving quite heavily together with the adjacent thin oil layer on the pipe wall. While WFDo/w-So flows occurred at extremely high mixture velocities where homogeneous dispersion of oil droplets across the pipe within the water phase was expected. The oil droplets could then be displaced with the same velocity as the continuous and faster phase (water) which justifies Ho < λo during WFDo/w-So flows. These phenomena in dispersed flows indicate the importance of considering the uniformity of the dispersion as also highlighted by Elseth (2001). 23

Fig. 19. Input oil volume fraction vs. the oil holdup.

The slip ratio (SR) which is defined as the ratio between the in-situ velocities of the oil and the water is also plotted versus λo (Fig. 20) for further elucidation of phase’s configurations. From this figure it can be clearly seen that in about 73% of the cases the slip ratio is less than unity (SR < 1) which implies that the oil phase had been the slower phase in most flow conditions. This is even perceptible at some higher oil input volume fractions (where

) which signifies the fact that

more viscous phase is more susceptible to shear stress acting on the fluid at the inner wall.

Fig. 20. Slip ratio vs. oil cut at different water superficial velocities.

3.5. Comparative Remarks on the flow patterns

The comparison between the presented flow patterns and those obtained by preceding investigators is, by and large, difficult and intricate. This emanates from the extensive experimental variables involved in the perception and definition of the flow patterns, including fluid properties, implemented methods, operational conditions, and inconsistent nomenclature and terminology. Nevertheless, the most comparable research work to this study is the one performed by Anosike (2007) despite the use of a waxy model oil (rather than a waxy crude oil) in his experiments. This is due to the fact that his research, to our knowledge, is the only available wax deposition study which has investigated wax deposition in two-phase flow under different oil-water flow patterns. Anosike identified five flow patterns, namely stratified with mixing at the interface (ST & MI), dispersion of oil in water and water (D o/w & w), dual dispersion of oil in water and water in oil (D o/w & D w/o), dispersion of oil in water (D o/w), and dispersion of water in oil (D w/o). These patterns were discerned after the completion of 74 oil-water flow experiments in a cold horizontal stainless steel pipe for oil and water superficial velocities between 0.18-2.0 m/s. Fig. 21 displays a comparison between the experimental data acquired in this study and the transition boundaries determined for the test results presented by Anosike (2007). The pinkish region in Fig. 21 demonstrates the scope limit of his investigation which also covers a large part of the flow pattern map of this study. In general, all of the flow patterns presented by Anosike can be equated with some of the patterns in this study by focusing on the fair similarities between the characteristics of the patterns. Accordingly, ST & MI and 24

D o/w & D w/o are equivalent to the DC flows (i.e. DC, WDC, WEA-DC) since all of these patterns are accompanied with the entrainment of the phases in one another while both the phases retain their continuity regardless of the degree of entrainment. D w/o resembles WEA-E in the type of dispersion wherein the water phase is fully dispersed into the oil phase. However, this type of dispersion has emerged at lower oil superficial velocities for WEA-E in comparison to D w/o. This is owing to the fact that all the flow patterns observed in the current study possessed water-in-oil emulsions at the interface which has intensified the viscosity differences. The induced higher viscosity difference is accompanied by increased shear between the phases (Al-Wahaibi et al., 2007). This, in turn, caused a higher instability at the interface which is responsible for an earlier transition from any dual continuous flows to full emulsion of water in oil in this study.

Fig. 21. Comparison of experimental data (dots) against the transition boundaries (solid blue lines) determined for the test results acquired by Anosike (2007).

D o/w & w and D o/w seem fairly analogous to WFDo/w-So and/or WFDo/w-TLo in a sense that water phase is the absolute dominant phase in these types of flows. Yet, the main difference between these flow patterns is pertinent to the relative wettability of the pipes used in both studies. As discussed in Section 2.3, the pipes of this study displayed a strong affinity for oil whereas Anosike employed stainless steel pipe which usually has an intermediate wettability (i.e., neither strongly water-wet nor oil-wet) (Lefebvre du Prey, 1973; Spijker et al., 2002). The strong oil-wetness of the pipe inner surface in the current study did not allow the full coverage of the pipe with the water phase despite the dominance of the water. In addition, this characteristic of the pipes was responsible for the formation of annular flow in this study at lower water velocities and its effect remained even at higher water velocities in the form of a persistent thin oil layer sliding on the pipe surface. Lastly, from Fig. 21, one may also note that Anosike did not find any types of stratified and stratified wavy flow in his study. This is because these two flow patterns are usually evident at lower mixture velocities than the ones determined in the scope of his study. Although annular flows are quit common in liquid-liquid flows, such patterns were not encountered in Anosike’s work. For this flow pattern to occur, two criteria must be satisfied – first that the two fluids must have extremely dissimilar viscosities and secondly that they must have relatively close densities (Bannwart et al., 2004). These are the criteria that are mainly met by viscous and heavy crude oils; however, Brauner et al. (1998) has emphasized the importance of the pipe size instead of viscosity ratio. Accordingly, systems of smaller pipe size are highly prone to the formation of stable annular flows and the density difference between the core and annular phases leads to the diversion of the core from pipe center toward an eccentric position.

25

The effectiveness of the

mentioned parameters can be well understood by comparing the information presented in Table 3. As can be seen, the oil-water viscosity ratio reported by Anosike is slightly greater than the one in this study; nevertheless, no annular flows was detected in his study due to the use of a relatively larger pipe diameter. This can be further confirmed by the results obtained by Al-Wahaibi et al. (2007) and Hanafizadeh et al. (2015) who also observed annular flows despite using low-viscous model oils.

Table 3 A comparison of Eötvös numbers and oil-water viscosity ratios in different studies. According to Brauner (2003), in oil-water systems two types of annular flows may form, namely oil-core and water-core annular flows. Sridhar et al. (2011) can be mentioned as a similar case to our observations who experienced a water-core annular pattern during the flow of a model oil and water in both horizontal and inclined pipes at relatively high flow rates. However, no entrainment of water droplets within the oil phase was detected due to the absence of bipolar species in the composition of the employed model oil. On the contrary, Wang et al. (2011) reported an annular flow with an oil core containing w/o emulsions during heavy crude oil/water flow in a stainless steel pipe. According to da Silva et al. (2006), the aforementioned discrepancies in the type of annular flows can be attributed to two primary factors which control the stabilization of specific annular-core configurations: pipe material and oil composition. Another type of flow structure that did not emerge in our experiments is intermittent flow. While the occurrence of intermittent flows are normally rare in oil-water systems (Brauner, 2003), they have been detected in a number of previous experimental works such as Al-Wahaibi et al. (2007), Hanafizadeh et al. (2015), Sotgia et al. (2008), and Wang et al. (2011). This pattern is characterized by the presence of large slugs (elongated or spherical) of one phase into the other which can attain varying sizes and lengths (Brauner, 2003; Sotgia et al., 2008). Previous experimental studies have revealed a large dependency of such flows to fluid properties and pipe geometry. Sotgia et al. (2008) observed slug flow in a 26-mm Plexiglas pipe while this flow did not emerge for the same types of fluids in a 40-mm Pyrex pipe. Furthermore, the addition of drag reducing polymer in Al-Wahaibi et al. (2007)’s experiment resulted in the complete conversion from slug flow into stratified flow at high superficial oil velocities. Al-Wahaibi et al. (2012) stated that the formation of intermittent flows in oil-water systems is favored by relatively high viscosity ratio and high interfacial forces. To examine the required circumstances for the formation of intermittent flows, the dominance of interfacial forces needs to be investigated. To this end, the definition of Eötvös number (Eo) for horizontal pipes defined by Ullmann and Brauner (2007) can be used:

Eo 

( w  o ) gD 2 8

(1)

26

where

is interfacial tension, g is gravity acceleration, D is the pipe size,

and

are oil and water

density, respectively. Based on this definition, higher values of Eo indicate that the system is less affected by interfacial forces and vice versa. From Table 3, it can be deduced that the formation of slug flow is more dependent on interfacial forces compared to viscosity ratio. The extremely large value of viscosity ratio (

= 900.98) in Sotgia et al. (2008)’s work using Pyrex pipe was not

sufficient to provide the condition for slug formation while Al-Wahaibi et al. (2007) detected slug flows for a significantly lower value of viscosity ratio (

= 5.5). In the current study, however,

none of the criteria defined by Al-Wahaibi et al. (2012) is satisfied which clearly explains the absence of this flow pattern under the applied conditions. Another striking feature in the present work is pertinent to the wax deposition during the flow. The inclusion of this phenomenon in the flow pattern classification of this study is a new attempt to relate the structure of the deposited layer to specific flow conditions in a pipeline. This in turn provides insights into the understanding of the flow behavior of waxy crude oils and the associated challenges in the field conditions.

4. Conclusions

A thorough experimental investigation was carried out on the flow patterns corresponding to the concurrent flow of a waxy crude oil and water in a carbon steel horizontal pipe at a temperature slightly above the WAT. The mechanisms responsible for each individual flow pattern were theoretically discussed and the following conclusions can be drawn:

(1) The specified flow patterns of waxy crude oil–water two-phase flows were found to be a function of the relative characteristics of the both phases, namely the relative viscosity, density, velocity and wetting properties. (2) In general, nine flow patterns were identified and named as follow: ST-PE, SW-PE, DC, WDC, WEA-PE, WEA-E, WEA-DC, WFDo/w-TLo and WFDo/w-So. Based on these flow patterns, a new flow pattern map was established in terms of fluids superficial velocities which deserves to be compared in future with the ones concerning waxy crude oils. (3) A discrepancy was found between the annular flows observed in this study and the conventional annular flows in a sense that the core appeared (in some cases) in a fullemulsion form surrounded by a layer of the continuous phase. (4) All the flow patterns were affected by the entrance effect and a layer of water-in-oil emulsion was observed for all the flow conditions. This implies that the entrance effect cannot be mitigated in liquid-liquid two phase flow studies when actual crude oils are applied even by 27

considering a sufficient ( /d) ratio and/or a specially designed mixing point. This is due to the natural emulsifiers existing within the crude oil compositions which entrap the water droplets upon their entrance into the oil phase. That is also the reason why emulsions are always encountered in oil transportation pipelines. (5) The effect of the emulsified water on the WAT of water-in-waxy-crude-oil emulsions was also evidenced to be influential in the earlier formation of wax crystals and specific flow patterns during the flow. The visual observations showed that despite maintaining the temperature of the system above the WAT of the dehydrated crude oil throughout the tests, there was still wax deposition for some of the flow conditions. Therefore, it is necessary to embed the term emulsion as a part of the flow pattern nomenclature in case of identifying even small portion of emulsions in such systems. (6) Wax deposition was only sensible during higher mixture velocities and the deposited wax layer was formed mostly on the top side of the pipe in a crescent-shaped configuration. The higher water and oil superficial velocities brought about thicker deposited wax layer on the pipe inner surface which is in disagreement with the findings in most previous studies regarding wax deposition. This is due to the exploiting a new and different mechanism for the formation of wax in the current study which needs to be also considered in this research area.

As a final analysis, it is not suggested to extend the obtained results of flow patterns of any liquid-liquid two-phase flow systems including model oils or non-waxy crude oils to those of waxy crude oils. Such comparisons are hardly plausible and further studies on waxy crude oils under twophase flow conditions are still essential. Since the waxy crude oil in two-phase flow is a relatively uncharted area of study, the results of this study can provide a platform for furthering research. In addition, it should be stressed that the results of this study provide a progressive introduction to help flow assurance engineers to understand the process of wax crystallization and deposition under multiphase flow conditions in horizontal pipelines, and to ultimately develop more effective wax management strategies.

5. ACKNOWLEDGMENTS The authors would like to express their sincere gratitude to the Ministry of Higher Education (MoHE) of Malaysia and University Teknologi Malaysia (UTM) for funding this research project via the Fundamental Research Grant Scheme (FRGS) Vote 4F136 and Research University Grant (RUG) Vote 01H68, respectively. We also would like to extend our sincere appreciation and gratitude to Petronas for providing us with the crude oil.

28

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Matzain, A., Apte, M.S., Zhang, H.-Q., Volk, M., Brill, J.P., Creek, J., 2002. Investigation of paraffin deposition during multiphase flow in pipelines and wellbores—part 1: experiments. Journal of energy resources technology 124, 180-186. Merino-Garcia, D., Correra, S., 2008. Cold flow: A review of a technology to avoid wax deposition. Petroleum Science and Technology 26, 446-459. Nädler, M., Mewes, D., 1997. Flow induced emulsification in the flow of two immiscible liquids in horizontal pipes. International journal of multiphase flow 23, 55-68. Ng, T., Lawrence, C., Hewitt, G., 2001. Interface shapes for two-phase laminar stratified flow in a circular pipe. International journal of multiphase flow 27, 1301-1311. Panacharoensawad, E., 2014. Wax Deposit Surface Characteristic under Single-phase and Water-inCrude-Oil Flow Conditions, Offshore Technology Conference. Offshore Technology Conference. Panacharoensawad, E., Sarica, C., 2013. Experimental Study of Single-Phase and Two-Phase Waterin-Crude-Oil Dispersed Flow Wax Deposition in a Mini Pilot-Scale Flow Loop. Energy & Fuels, 130809132746004. Piroozian, A., Hemmati, M., Ismail, I., Manan, M.A., Bayat, A.E., Mohsin, R., 2016a. Effect of emulsified water on the wax appearance temperature of water-in-waxy-crude-oil emulsions. Thermochimica Acta 637, 132-142. Piroozian, A., Manan, M.A., Ismail, I., Mohsin, R., Bayat, A.E., Onuoha, M.D.U., Hemmati, M., 2016b. Mixture temperature prediction of waxy oil–water two-phase system flowing near wax appearance temperature. Chinese Journal of Chemical Engineering 24, 795-802. Rodriguez, O., Oliemans, R., 2006. Experimental study on oil–water flow in horizontal and slightly inclined pipes. International Journal of Multiphase Flow 32, 323-343. Sarica, C., Panacharoensawad, E., 2012. Review of Paraffin Deposition Research under Multiphase Flow Conditions. Energy & Fuels 26, 3968-3978. Shang, W., Sarica, C., 2010. Temperature Prediction for Two-Phase Oil/Water Stratified Flow, 7th North American Conference on Multiphase Technology. BHR Group, Banff, Canada pp. 251-264. Shang, W., Sarica, C., 2013. A Model for Temperature Prediction for Two-Phase Oil/Water Stratified Flow. Journal of Energy Resources Technology 135, 032906. Sotgia, G., Tartarini, P., Stalio, E., 2008. Experimental analysis of flow regimes and pressure drop reduction in oil–water mixtures. International journal of multiphase flow 34, 1161-1174. Spijker, H.T., Busscher, H.J., van Oeveren, W., 2002. Influence of abciximab on the adhesion of platelets on a shielded plasma gradient prepared on polyethylene. Thrombosis research 108, 57-62. Sridhar, S., Zhang, H.-Q., Sarica, C., Pereyra, E.J., 2011. Experiments and Model Assessment on High-Viscosity Oil/Water Inclined Pipe Flows, SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. Sullivan, A.P., Kilpatrick, P.K., 2002. The effects of inorganic solid particles on water and crude oil emulsion stability. Industrial & engineering chemistry research 41, 3389-3404. Tambe, D.E., Sharma, M.M., 1993. Factors controlling the stability of colloid-stabilized emulsions: I. An experimental investigation. Journal of colloid and interface science 157, 244-253. Tan, C., Li, P., Dai, W., Dong, F., 2015. Characterization of oil–water two-phase pipe flow with a combined conductivity/capacitance sensor and wavelet analysis. Chemical engineering science 134, 153-168. Trallero, J., Sarica, C., Brill, J., 1997. A study of oil-water flow patterns in horizontal pipes. SPE Production & facilities 12, 165-172. Tritton, D.J., 2012. Physical fluid dynamics. Springer Science & Business Media. Ullmann, A., Brauner, N., 2007. The Prediction of Flow Pattern Maps in Minichannels. Multiphase Science and Technology 19, 49-73. Vielma, M.A., Atmaca, S., Sarica, C., Zhang, H.-Q., 2008. Characterization of oil/water flows in horizontal pipes. SPE Projects, Facilities & Construction 3, 1-21. Visintin, R.F., Lockhart, T.P., Lapasin, R., D’Antona, P., 2008. Structure of waxy crude oil emulsion gels. Journal of Non-Newtonian Fluid Mechanics 149, 34-39. Vuong, D.H., Zhang, H.-Q., Sarica, C., Li, M., 2009. Experimental study on high viscosity oil/water flow in horizontal and vertical pipes, SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers, New Orleans, Louisiana.

31

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32

Figure Captions

Fig. 1. Oil-water flow patterns: (a) separated flows and (b) dispersed flows (Elseth, 2001). Fig. 2. Schematic diagram of the flow loop facility: 1. oil tank, 2. oil bypass line, 3. transmitter and receiver, 4. ultrasonic flow meter, 5. water tank, 6. water bypass line, 7. copper tubes, 8. mezzanine platform, 9. centrifugal pump, 10. ball valve, 11. Y mixing point, 12. flange, 13. pressure transducer, 14. mixture line, 15. camera/video recorder, 16. view box, 17. black light fluorescent tube, 18. air compressor, 19. transparent acrylic pipe, 20. pneumatic quick closing valve, 21. drainage line, 22. graduated beaker, 23. temperature transducer, 24. oil/water separator, 25. water return line, 26. oil return line, 27. chiller, 28. computer, 29. National Instrument (NI) data acquisition system, 30. linking wire and 31. digital temperature meter. Fig. 3. Schematic diagram of oil–water mixing point. (angles indicated are in degrees) Fig. 4. Oil/water separator. Fig. 5. Illustrations of the measured contact angles on inner pipe surfaces: (a) acrylic and (b) carbon steel. Fig. 6. Flow pattern classification for waxy crude oil-water in a horizontal two-phase flow system at 28 °C and WAT of 24 °C: (a) ST-PE, (b) SW-PE, (c) DC, (d) WDC, (e) WEA-PE, (f) WEA-E, (g) WEA-DC, (h) WFDo/w-TLo and (i) WFDo/w-So. Fig. 7. Experimental flow-pattern map for the current study. Fig. 8. The interface shapes responsible for the height of the oil phase: (a) at motion and (b) at rest. Fig. 9. Laceration of the interface as the momentum and viscous forces prevailed over the interfacial force during transformation of flow from SW-PE into DC. = 0.2 m/s & = 0.7 m/s. Fig. 10. Recognition of wax deposit via visual inspection of residual oil components on the pipe wall after initial drainage of the trapped fluids within the transparent pipe for different flow conditions: (a) no tangible wax precipitation on the pipe wall, (b) wax sediment on the top side of the pipe. Fig. 11. Image of fluids (a) at motion, (b) at rest and (c) after drainage for free water measurement. = 0.5 m/s & = 0.1 m/s. Fig. 12. Characterization of fully dispersed water in the absence of free water during the measurements. = 0.6 m/s & = 0.3 m/s. Fig. 13. Front and side view photos of water growth on the pipe wall as water superficial velocity increased for a constant oil superficial velocity during WFDo/w-TLo flow. Fig. 14. Presence of the w/o emulsion at the interface during shutdown period and after natural segregation of the phases. = 0.2 m/s & = 0.8 m/s. Fig. 15. The flow of oil and water on the pipe wall in the form of the snake-skin pattern during WFDo/w-So. = 0.5 m/s & = 1.0 m/s. Fig. 16. Relationship between the wax thickness and the superficial velocities of the phases: (a) , (b) , (c) and (d) . (Photos have been taken during pipe drainage after the completion of each run)

33

Fig. 17. Pressure gradient in oil/water flow – low mixture velocities. Fig. 18. Pressure gradient in oil/water flow – moderate to high mixture velocities. Fig. 19. Input oil volume fraction vs. the oil holdup. Fig. 20. Slip ratio vs. oil cut at different water superficial velocities. Fig. 21. Comparison of experimental data (dots) against the transition boundaries (solid blue lines) determined for the test results acquired by Anosike (2007).

34

Oil phase Water phase

Stratified Mixed (SM) with oil droplets in water

Stratified Wavy (SW) Stratified Mixed (SM) with water droplets in oil

Dual continuous (DC)

Stratified Smooth (SS)

(a)

Homogenous dispersion of oil in water (HDo/w) Inhomogeneous dispersion of oil in water (IDo/w)

Dispersion of oil in water and water layer (Dow&w) Inhomogeneous dispersion of water in oil (IDw/o) Dispersion of water in oil and oil layer (Dw/o&o)

Homogenous dispersion of water in oil (HDw/o)

(b) Fig. 1. Oil-water flow patterns: (a) separated flows and (b) dispersed flows (Elseth, 2001).

35

Fig. 2. Schematic diagram of the flow loop facility: 1. oil tank, 2. oil bypass line, 3. transmitter and receiver, 4. ultrasonic flow meter, 5. water tank, 6. water bypass line, 7. copper tubes, 8. mezzanine platform, 9. centrifugal pump, 10. ball valve, 11. Y mixing point, 12. flange, 13. pressure transducer, 14. mixture line, 15. camera/video recorder, 16. view box, 17. black light fluorescent tube, 18. air compressor, 19. transparent acrylic pipe, 20. pneumatic quick closing valve, 21. drainage line, 22. graduated beaker, 23. temperature transducer, 24. oil/water separator, 25. water return line, 26. oil return line, 27. chiller, 28. computer, 29. National Instrument (NI) data acquisition system, 30. linking wire and 31. digital temperature meter.

36

Fig. 3. Schematic diagram of oil–water mixing point. (angles indicated are in degrees)

37

Fig. 4. Oil/water separator.

38

(a)

(b) Fig. 5. Illustrations of the measured contact angles on inner pipe surfaces: (a) acrylic and (b) carbon steel.

39

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

Fig. 6. Flow pattern classification for waxy crude oil-water in a horizontal two-phase flow system at 28 °C and WAT of 24 °C: (a) ST-PE, (b) SW-PE, (c) DC, (d) WDC, (e) WEA-PE, (f) WEA-E, (g) WEA-DC, (h) WFDo/w-TLo and (i) WFDo/w-So.

40

Fig. 7. Experimental flow-pattern map for the current study.

41

Flow direction Oil

2 cm

Water

(a)

W/o emulsion at the interface

1.6 cm

Residual oil components on the pipe surface

(b)

Fig. 8. The interface shapes responsible for the height of the oil phase: (a) at motion and (b) at rest. = 0.1 m/s & = 0.3 m/s.

Flow direction

Fig. 9. Laceration of the interface as the momentum and viscous forces prevailed over the interfacial force during transformation of flow from SW-PE into DC. = 0.2 m/s & = 0.7 m/s.

42

Relatively clean

Inception of wax deposition

(a) Thin layer of wax deposit

Thicker layer of wax deposit

(b) Fig. 10. Recognition of wax deposit via visual inspection of residual oil components on the pipe wall after initial drainage of the trapped fluids within the transparent pipe for different flow conditions: (a) no tangible wax precipitation on the pipe wall, (b) wax sediment on the top side of the pipe.

Complete coverage of the inner pipe wall with the oil phase

(a)

43

Water-free oil W/o emulsion

Free water

(b) Oil phase W/o emulsion Water phase

(c) Fig. 11. Image of fluids (a) at motion, (b) at rest and (c) after drainage for free water measurement. = 0.5 m/s & = 0.1 m/s.

Fig. 12. Characterization of fully dispersed water in the absence of free water during the measurements. = 0.6 m/s & = 0.3 m/s.

(a)

(b)

44

(c)

Fig. 13. Front and side view photos of water growth on the pipe wall as water superficial velocity increased for a constant oil superficial velocity during WFDo/w-TLo flow.

Fig. 14. Presence of the w/o emulsion at the interface during shutdown period and after natural segregation of the phases. = 0.2 m/s & = 0.8 m/s.

Fig. 15. The flow of oil and water on the pipe wall in the form of the snake-skin pattern during WFDo/w-So. = 0.5 m/s & = 1.0 m/s.

(a)

(b)

45

(c)

(d)

Fig. 16. Relationship between the wax thickness and the superficial velocities of the phases: (a) , (b) , (c) and (d) . (Photos have been taken during pipe drainage after the completion of each run)

Fig. 17. Pressure gradient in oil/water flow – low mixture velocities.

46

Fig. 18. Pressure gradient in oil/water flow – moderate to high mixture velocities.

Fig. 19. Input oil volume fraction vs. the oil holdup.

47

Fig. 20. Slip ratio vs. oil cut at different water superficial velocities.

Fig. 21. Comparison of experimental data (dots) against the transition boundaries (solid blue lines) determined for the test results acquired by Anosike (2007).

48

Table Captions

Table 1 Factors affecting flow patterns during oil-water two phase flow based on the previous studies. Table 2 Physical properties of waxy crude oil used in this study. Table 3 A comparison of Eötvös numbers and oil-water viscosity ratios in different studies.

49

Table 1 Factors affecting flow patterns during oil-water two phase flow based on the previous studies.

50

Investigated main factor

Associated sub-factors

Significant remarks

Length-todiameter ratio



The ratio of pipe entrance length to its diameter ( /d) should be at least 200 to minimize the entrance effect on flow patterns (Trallero et al., 1997)

Pipe diameter



Under the same flow conditions, different flow patterns occur in different pipe sizes (Mandal et al., 2007) The decrease in pipe diameter leads to the dominance of interfacial forces over gravity forces (Brauner and Maron, 1992)



Mixing-point design



A proper mixing-point design can mitigate the entrance effect by assuring smooth introduction of the fluids into the system (Nädler and Mewes, 1997)

Inclination



Depending on the pipe inclination angle, the interaction between inertial, gravity, and buoyancy forces may cause a delay or acceleration in the emergence of specific flow patterns (Hanafizadeh et al., 2015) By increasing the pipe inclination angle from horizontal position, stratified flow becomes wavier (Rodriguez and Oliemans, 2006)

Pipe geometry 

Wall material



 



Change of the pipe material brings about changes in the observed flow patterns for the same type of fluids and flow conditions (Angeli and Hewitt, 1999) The pipe wall wettability influences the type of coreannular flow (i.e., oil-core or water-core flows) (Bordalo and Oliveira, 2007) The pipe wall wettability with respect to the phases is one of the crucial factors controlling the orientation and the degree of the curvature during stratified flows (Ng et al., 2001) Oil-wet, water-wet, and intermediate-wet surfaces lead to the formation of convex, concave and planar interfaces, respectively (Brauner et al., 1998) Continued on next page

51

Table 1 Factors affecting flow patterns during oil-water two phase flow based on the previous studies – Continued Investigated main factor

Associated sub-factors

Significant remarks

Temperature



Fluid physical properties are significantly influenced by variations in the system’s temperature. Such variations can alter the fluids’ momentum, and in turn, the flow patterns (Huang et al., 2011)

Pressure



The effect of pressure on the physical properties of liquid-liquid systems is usually considered negligible since oil and water are always treated as incompressible fluids (Tritton, 2012) In case of employing two partially miscible liquids, however, pressure greatly affects the flow patterns by changing the solubility, interfacial tension, and density of the phases (Lin and Tavlarides, 2009)



Flow conditions

Velocity







Superficial phase velocities act directly on the effectiveness and magnitude of all the three forces (momentum, viscous, and interfacial forces) involved in forming the interface (Al-Wahaibi et al., 2012) At low mixture velocities where the gravity is the dominant force, the interface tends to attain a plain shape (Zhang et al., 2012) Separated or stratified flows have been observed at low mixture velocities, whereas dispersed flows appeared at high mixture velocities (Al-Wahaibi and Angeli, 2007)

Water volume fraction



Dispersed flows may become evident even at low velocities on conditions that the input water volume fraction is either very low or very high (Elseth, 2001)

Density



The magnitude of buoyancy and gravity forces is a direct function of density (Hanafizadeh et al., 2015) At the low relative velocities, the density difference between the two fluids results in the occurrence of stratified flow (Angeli and Hewitt, 2000; Yusuf et al., 2012) No stratified flow can be seen when utilizing liquids of

 Fluid properties



52

equal densities (i.e., 

Viscosity





Interfacial tension

= 1) (Charles et al., 1961)

Apart from velocity, viscosity also controls the momentum force during the flow in a way that higher viscosity difference between the two phases leads to higher interfacial instability (Al-Wahaibi et al., 2012) In case that the two fluids have extremely dissimilar viscosities and relatively close densities core annular flow can be formed (Bannwart et al., 2004) From moderate to high relative velocities, a faster transition from stratified to non-stratified flows occurs due to the higher interface instability caused by lower interfacial tension and/or higher oil viscosity (AlWahaibi et al., 2012)

Table 2 Physical properties of waxy crude oil used in this study. Test (units) API gravity (°API) WAT (°C) Pour point (°C) Flash point (°C) Wax content (wt %) Asphaltenes (wt %) Water content (vol. %) Characterization factor Dynamic viscosity @ 40 °C (mPa·s) Interfacial tension @ 28 °C (dynes/cm)

Method ASTM D1298 DSC ASTM D97 ASTM D92 UOP 46 IP 143 ASTM D4377 UOP 375 ASTM D445 du Noüy ring

Results 36 24 18 130 16.15 <0.06 0.05 11.8 2.22 32.9

Table 3 A comparison of Eötvös numbers and oil-water viscosity ratios in different studies. Oil-water

Slug flow

viscosity ratio

observed

Annular flow observed

8.81

2.22 @ 40 ℃

No

Yes

40

10.88

900.98 @ 20 ℃

No

Yes

Sotgia et al. (2008) – Plexiglas

26

4.60

900.98 @ 20 ℃

Yes

Yes

Al-Wahaibi et al. (2007)

14

1.04

5.50 @ 25 ℃

Yes

Yes

25.4

3.62

628.10 @ 60 ℃

Yes

Yes

Pipe size (mm)

Eo

38.1

Sotgia et al. (2008) – Pyrex

Author(s)

Current study

Wang et al. (2011)

53

Hanafizadeh et al. (2015) Anosike (2007)

20

-

4.50 @ 25 ℃

Yes

Yes

52.5

-

5.12 @ 40 ℃

No

No

54

Graphical abstract

55

Highlights 

A new flow pattern map for a waxy crude oil and water is proposed.



A layer of water-in-oil emulsion was evidenced for all the flow conditions.



Entrance effect cannot be eliminated for waxy crude oils regardless of the design.



New configurations were discovered for annular flows.



The wax appearance temperature was affected by the emulsified water.