Article pubs.acs.org/EF
Role of Electrical Submerged Pumps in Enabling AsphalteneStabilized Emulsions Sebastiano Correra,*,† Massimo Iovane,† and Stefano Pinneri‡ †
eni, via Emilia 1, 20097 San Donato Milanese, Italy eni, via Maritano 26, 20097 San Donato Milanese, Italy
‡
ABSTRACT: Many oilfield development projects require artificial lift systems, i.e., methods to enhance well fluid production that are needed when the reservoir pressure is too low to allow for the produced fluid to reach the surface. Such an approach is of particular interest for mature oilfields (such as those in the Middle East and North Africa) and for many of the upcoming deepwater and ultra-deepwater fields under development around the world. Artificial lifting can be achieved by gas lifting or through a pump installed into the well. For subsea downhole applications, a progressive cavity pump (PCP) or (centrifugal) electrical submersible pump (ESP) is employed. ESP systems are having, in particular, wide spreading, essentially as a result of the good efficiencies and high rates and depth. In search of means for maximizing the productivity of each well that sometimes leads to looking for producing the maximum in the shortest possible time, these pumps are seen as a sort of panacea. In this work, a dangerous possible drawback is highlighted: if the system is not correctly designed, it can result in a perfect tool to generate very viscous asphaltene-stabilized emulsions. The behavior of the system is described along with the impacts generated on the pump. A verification criterion is proposed to be used during ESP design and selection of correct working conditions, and a case study is presented.
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INTRODUCTION
Artificial lift is needed where produced fluids cannot reach the surface as a result of insufficient reservoir pressure (a typical case is that linked to well depletion). Nowadays, it is often used to increase the production flow rate since the beginning of the life of a well: by decreasing bottomhole pressure (BHP), much more oil can be produced from the well, thanks to the energy added by the pump to bring fluid to the surface. More than 60% of producing oil wells require some type of assisted lift technology to keep producing, and several technologies are employed for the artificial lifting: (1) gas lift, by injecting gas in the tubing to reduce the weight of the hydrostatic column, (2) hydraulic subsurface pump, such as reciprocating piston pumps (e.g., rod pump), jet pumps, or hydraulic submersible pumps (HSPs), making use of the driver fluid to provide the work to push the reservoir fluid to the surface, (3) progressive cavity pumps (PCPs), deploying a downhole stator and a rotor usually powered by a surface motor, and (4) electric submersible pumps (ESPs). For many onshore and subsea applications (Figure 1), ESP and PCP are the outstanding favorites.1 Indeed, about 20% of producing wells worldwide are equipped with ESPs; this is also due to the versatility of this technology, able to deal with a huge range of flow rates and head losses. The overall system consists of a multistage downhole pump, a separator or protector (to prevent produced fluids from entering the electrical motor), and an electric power cable connecting the motor of the downhole pump to the surface power transformer. Each stage of the ESP is composed of two main parts: the impeller (rotor), which rotates at the motor speed and transmits momentum to the fluid, increasing its kinetic energy, and the diffuser (stator), which is the © XXXX American Chemical Society
Figure 1. Schematic of ESP connection to a floating production, storage, and offloading (FPSO).
standing part, addressing the fluid to the next stage and converting kinetic energy to pressure energy. ESPs are manufactured with many diameters and fall into two general categories, depending upon flow rate: radial flow design, applied generally for flow rate up to 2000 barrels per day (bpd), and mixed flow design (i.e., presents also an axial component), applied generally for flow rate >2000 bpd. The wide diffusion of ESP, either for on- or offshore application, can lead to underestimation of some potential operational problems, and care has to be taken in the design, development, and operation phases to avoid undesired effects, such as premature failure of the electrical motor or rotating parts. An extensive literature review on ESP problems was Special Issue: 16th International Conference on Petroleum Phase Behavior and Fouling Received: September 15, 2015 Revised: November 6, 2015
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DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels performed in 1999,2 and a first indication about potential problems as a result of asphaltene deposition was reported. Asphaltene precipitation problems in ESP were also reported by Shimokata and Yamada,3 who acquired big experience in applying an artificial lift with ESPs in offshore fields. In that case, it was decided to inject xylene in the annulus periodically to remove the deposit. Such a decision is only mitigating the actual problem that lays behind the formation of the deposit, while in the present work, a different approach to the issue is proposed. On the other hand, emulsion formation problems are also known when operating an ESP. For sake of example, Zhizhuang and Bassam4 report that, in the Penglai 19-3 offshore oil field (South China Sea), preliminary testing on ESP showed a strong increase in the viscosity of the produced fluid as a consequence of water/oil (w/o) emulsion formation. For this reason, a chemical injection line was included for emulsion breaker addition. The formation of viscous emulsion was experienced in a number of wells, and downhole injection of chemicals, for the time being, was found as a sometimes effective temporary solution in breaking the formed emulsion. The effect of emulsion formation in ESP has also been considered by Yang et al.,5 and a significant impact of this phenomenon was found. A significant presence of problems in ESP, linked to either asphaltene deposits, emulsions, or both, was experienced also by us. The need to explain and better predict these problems led us to a reflection on the physical mechanisms underlying possible problems in ESP application. In view of the widespread diffusion of ESP, pushed by the need to obtain a faster return of the investment, we draw attention on a potential problem that needs to be carefully examined before deciding on adequacy of ESP application: the danger that the ESP during the production life of the field becomes the perfect viscous-slurry-making machine.
scientific community has reached in the last few years an almost unanimously shared vision on this phenomenon: asphaltene destabilization is the result of a reduction in the solvating power of the oil hydrocarbon matrix, and this change is essentially linked to changes of oil density. In crude oil, a little amount of relatively large size “solute” asphaltene molecules is dissolved in a huge amount of relatively small size “solvent” molecules. Such a system can be described by means of the Flory−Huggins theory.6 In this approach, a key role is played by the asphaltene−oil interaction parameter χ, which, in turn, is proportional to the difference between solubility parameters of asphaltene (δasp) and oil (δoil). In an oil well, the “live oil” (or produced fluid or reservoir fluid) flows from the reservoir to the surface; in this path, it undergoes a pressure drop along the tubing. This pressure reduction changes the solvating power of live oil, inducing a decrease of average bulk density of oil, and thus a decrease of its solubility parameter δoil and an increase of its molar volume voil. On the other hand, even if this pressure variation also affects δasp, its variation is much less pronounced. For this reason, as the oil rises along the tubing, the interaction parameter χ increases. In this way, it may exceed the critical value (χ = 1), at which precipitation starts (i.e., the “onset” condition). Continuing along the tubing, the system becomes more and more unstable, eventually inducing deposit formation (Figure 3).
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ASPHALTENE DEPOSITION PROBLEM Because of the fact that it comprises tens of thousands of compounds, crude oil from a practical point of view is a compositional continuum, and asphaltene is a fraction of this continuum. Asphaltenes are very complex molecules, with characteristics and amount strongly depending upon the crude oil source and reservoir conditions. They may deposit in wellbore or in the tubing, causing reduction of oil production (Figure 2), but they can affect pipelines and oil treatment facilities as well as heat exchangers and separators. The
Figure 3. χ as a function of the pressure along the tubing.
If pressure drops below the bubble pressure of oil, a vapor phase (containing lighter compounds) separates. This vaporization of light compounds causes an increase of the average bulk liquid density, and this, in turn, tends to stabilize the system again. For this reason, asphaltene deposits in tubing are usually located in the neighborhood of the zone in which the bubble pressure is reached. A more accurate description of this model is provided in Correra and Merino Garcia.7 The same phenomenon can happen as well at the bottomhole, where over time, as a result of oil being produced, reservoir pressure locally decreases. This leads to the increase of the interaction parameter χ, which may ultimately exceed the critical value, resulting in asphaltene deposition at the bottomhole.
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EMULSION PROBLEM During the entire life of the field, crude oil production is always accompanied by water production,8 even though emulsion formation is a non-spontaneous process because the total free
Figure 2. Asphaltene deposit removed from a tubing. B
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels energy of formation of an emulsion, ΔG, is positive. For this reason, energy is required to produce the droplets. Emulsions form naturally during the crude oil production (Figure 4), and their presence may have a strong impact on the crude oil production and treatment facilities.
In studies on the preparation of the emulsion, the drop size is found to decrease as the mixing speed increases, although it seems that an asymptotic value could be reached for higher speeds. This is in accordance with current knowledge on turbulent emulsification,9 in which two opposite mechanisms are accounting for dispersion: one is droplet breakup produced by the intense shear stress in the region near the impeller, and the other one is coalescence of droplets in the regions of fluid circulation. Both mechanisms are present during emulsification, although droplet breakup dominates the process at the first stages of mixing. Later, a dynamic equilibrium between breakup and coalesce is achieved, and consequently, a steady drop diameter is attained.
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ASPHALTENE-STABILIZED EMULSIONS
Given the above premises and scenario, destabilization of asphaltene may have other undesirable effects when an aqueous phase is present: it was found that, if they are near or above the point of incipient flocculation, asphaltenes stabilize w/o emulsions.10 Conditions of incipient flocculation of asphaltene correlate very well with a considerable increase of rheological resistance of the interface between the oil and water phase. Stabilization of w/o emulsions is caused by the buildup of a coherent layer of asphaltenes at the w/o interface. 11 Asphaltenes are trapped on the interface, and for this reason, the film resists compression and deformation.12−16 Droplets of w/o emulsions usually would tend to coalesce and flocculate, increasing their size, and settle. Instead, the highly elastic or rigid film of asphaltene on the interface results in unusual emulsion’s stability. According to this framework, pressure draw-down inside the tubing tends to reduce asphaltene stability in the bulk phase; near the point of incipient flocculation, asphaltene tends to concentrate at the w/o interface and to form solid particles that generate a rigid layer at the w/o interface. Both of these phenomena may stabilize emulsions. The presence of solids and salts may indeed stabilize emulsions by adsorbing in the w/o interface or by adsorbing in the already available interfacial film.17 Adsorbed solids constitute a steric barrier, hindering collision among drops, effective film drainage, and droplet coalescence and flocculation. They also increase the mechanical rigidity and viscosity of the interface. Emulsions formed near the point of asphaltene precipitation and in the presence of small solid particles will be particularly stable. The same behavior would be seen at the bottomhole, where, over time, the pressure decreases (as a result of reservoir production), affecting the stability of asphaltene and eventually resulting in emulsion formation. If the proper energy contribution would be present or applied, emulsion formed under such conditions would be pretty stable. It is possible to synthesize the overall picture as follows: asphaltenes lend rigidity to interfaces, while solids prevent bridging among water droplets.18 The increase of interface rigidity may lead, to the limit, more to a suspension-like system than to an emulsion.
Figure 4. Emulsion formed in oil and gas equipment.
In general, emulsions are formed from produced fluid flowing through valves, chokes, and pumps (such as ESP) as a result of the mixing effect (low agitation energy), which may provide the necessary energy. Emulsions are stabilized by natural surfactants or fine solids existing in the crude oil phase. The problem of the emulsion presence is worsened in oil fields production. In fact, they operate across the full range of water cuts (WCs, 0−90%) over their life. Initially, as a result of the low water content, emulsions would not be an issue (Figure 5); however, over time, this problem will certainly appear.
Figure 5. Typical oil, gas, water, and sand/solid production profile over time.
Emulsion negative effects are even worst when dealing with viscous crude oils, which tend to emulsify readily, creating problems that are related to the increased overall viscosity. When produced fluid flows from the reservoir into the wellbore and centrifugal pump impeller, liquids composing the produced fluid (i.e., oil and water) are subject to vigorous stirring, resulting in emulsification. Solids can potentially stabilize an emulsion by adsorbing onto the water/oil interface directly or by adsorbing onto a film already stabilized by a material, such as a surfactant. Solids adsorbed on the interface or on the emulsion films can create a steric barrier between adjacent water drops, hindering collision among drops and coalescence. Usually, solids capable of stabilizing emulsions are in the sub-micrometer to micrometer range, and emulsion stability increases with a decreasing particle size and an increasing particle concentration. A decrease in the average drop size tends to result in even more stable emulsions.
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FLOW FIELD INSIDE THE ESP ESPs employed downhole are multistage, vertically oriented centrifugal pumps. A driven impeller followed by a diffuser, which directs flow to the next stage, constitutes each stage. Stages are stacked in series to incrementally increase the pressure to the one needed for the desired flow rate. In each C
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels stage, fluid enters axially, is caught up in the impeller blades, and is whirled tangentially and radially outward, until it leaves through all circumferential parts of the impeller into the diffuser (Figure 6). The fluid gains both velocity and pressure while
emulsion may be drastically altered by changes in its drop size distribution. Emulsion viscosity is usually expressed through the relative viscosity, i.e., the ratio between the viscosity of the emulsion and the viscosity of the continuous phase η ηr = emulsion ηoil (1) Various empirical equations have been proposed, linking the relative viscosity to the volume fraction of the dispersed phase ϕ: polynomial ηr = 1 + Aϕ + Bϕ2 + Cϕ3 + ...
(2)
exponential ηr = exp[k 0ϕ + k1]
Pal and Rhodes
ηr = [1 − k 0kαϕ]−[η]
Figure 6. Flow path within an ESP stage.
(3)
27
(4)
In these equations, A, B, C, k0, k1, and kα are empirical parameters. Many other similar equations have been proposed. These equations are empirically fitted to some experimental data and show (of course) similar trends (Figure 7).
passing through the impeller. The diffuser decelerates the flow and further increases pressure. The high rotational speed of the impeller imposes great centrifugal forces to the fluid, which is accelerated. In the following diffuser, this kinetic energy is converted in pressure energy.19,20 It is to be noticed that, in their analysis of the effect of fluid viscosity on the overall performance of the ESP, Amaral et al.21 found that a very strong effect is linked to flow interactions between impellers and diffusers. Passing through the pump, well’s fluid may be subject to high values of shear rate. For example, fluids flow in a gap of about 10 mm to be pushed by the impeller at a typical rotational speed of 3600 rpm. This value corresponds to a shear rate of the order of 700 s−1 or more. The fact that, in a compact volume, it is possible to transmit a high power to fluids is one of the main reason of the success of ESP; on the other hand, it is impossible not to wonder if the transmission of such power to the fluid, in the presence of two liquid phases, leads to the formation of emulsions. Indeed, an impressive geometric and dynamic analogy holds between ESP and the rotor−stator homogenizer, i.e., an apparatus able to prepare an emulsion by comminuting a dispersed phase. Rotor−stators consist of a fastspinning inner rotor with a stationary outer sheath (stator) to homogenize samples through mechanical tearing and shear fluid forces. Centrifugal ESPs are employed to increase the oil production, but, in general, a WC is often present in produced fluids. Besides, this WC increases in the years during the field production life. Now, the application of a high shear rate in a rotor−stator geometry is just the procedure to obtain, as output, a finely dispersed w/o emulsion.
Figure 7. Relative viscosity versus volume fraction of the dispersed phase.
When the WC is increased, the relative viscosity starts from 1 (corresponding to the viscosity of pure oil) and increases slowly at the beginning. However, as the water content further increases, a dramatic growth happens, until divergence for a critical value of the WC. From the foregoing, it is apparent that the system can easily generate very viscous w/o emulsions when the WC is relatively high. However, the situation may be even worse. While many correlations have been developed for the viscosity of emulsions as a function of the water content, many other variables, such as droplet diameter, droplet shape, etc., have been much less addressed but could cause an increase of viscosity. In particular, the effect of the size may be very strong:28 the overall viscosity of an emulsion, at a constant
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EFFECT ON SYSTEM RHEOLOGY In an emulsion, one liquid (the dispersed phase, produced water in our case) is dispersed in the other one (the continuous phase, oil in our case). Many different correlations were developed for both emulsions22−25 and suspensions.26 Viscosity of w/o emulsions strongly increases by increasing the water volume fraction (WC) and amount of fine solids dispersed and decreasing the temperature. Besides, the viscosity of an D
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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water content, is inversely proportional to the droplet size. For this reason, the effect of the droplet size is of particular importance when considering the introduction of a centrifugal pump. In fact, a pump is able to change the droplet size distribution by breaking the droplets into smaller sizes, by adding a large quantity of energy with a high shear stress. Mixing energy supplied to fluid in a rotor−stator system may be estimated as the product mixing intensity for mixing time. The mixing intensity is related to the power input of the stirring device through the mixing speed (rpm), although the actual amount of energy that is dissipated by the breaking of droplets cannot be easily assessed. However, the drop size can be correlated to mixing intensity and mixing time. To evaluate the droplet size of produced emulsion, it is possible to employ the following equation,29−32 which assumes that the flow regime is turbulent-viscous (i.e., interfacial stresses are balanced by the viscous stresses). In this regime, breakup of droplets occurs under shear stresses across the continuous medium. dmax = CN −3/2D−1ρc−1/2 ηc−1/2γ
Table 2. Oil Characterization
(5)
dmax C N D ρc ηc γ
maximum droplet diameter constant rotating speed impeller diameter density of the continuous phase viscosity of the continuous phase interfacial tension
unit
adopted value
s−1 m kg m−3 Pa s mN m−1
0.02807 60 0.08 800 0.02 50
m
When the produced fluid passes in the ESP, the droplets after a strong mixing are reduced in diameter. According to traditional view on the emulsion production, the droplet diameter results from a balance between viscous stress, due to shear and droplet coalescence. However, the layer of precipitated asphaltenes formed on the o/w interface reduces the coalescence rate among the droplets. The just described phenomenon happen in each stage of the pump and thus the viscosity of the system increases. Effects of changes induced on the actual overall viscosity and then on power required from the electrical motor should not be underestimated. In fact, the energy dissipated by the mixing is given by ε=
γη̇ ρ
property
unit
result
American Petroleum Institute (API) gravity total acid number (TAN) total base number (TBN) sulfur mercaptan sulfur density at 15 °C viscosity at 15 °C pour point water cut (WC)
deg mg of KOH/g mg of KOH/g %, m/m ppm kg/m3 Pa s °C %, v/v
18.6 0.46 0.62 3.25 14 942 2.14 +4 42
The anhydrous oil shows non-Newtonian behavior below 30 °C. In presence of natural emulsion (42% WC) its behavior becomes non-Newtonian below 76 °C. It has been observed that the presence of water generates highly viscous emulsion, especially at lower temperatures (see Figure 8). Produced crude oil showed a strong tendency to generate very stable, persistent, and viscous emulsions; at 50 °C, stable emulsions with a WC up to 60% have been obtained from the well. A proper study to assess the asphaltene stability/instability has never been performed before installing ESPs in the oil wells, even if evidence of asphaltene instability has been historically observed in the field. The frequent operations to “clean” ESPs, from not well-defined “slugs” (asphaltene, sand, and emulsions), are proof that the combination of the characteristics of such a fluid and energy addition by ESP could result in negative impacts on oil production and maintenance costs of equipment (Table 3). When evaluating the introduction of ESP in an existing well, the first step should be to assess the asphaltene stability/ instability. The oil has a low asphaltene stability, as showed in Figure 9, obtained according to the method proposed in ref 33. The curve is based on Company’s historical data and separates stable from unstable oils. The representative point for the considered case falls clearly inside the asphaltene unstable area. Performing a more accurate evaluation with the method described in ref 7, the instability pressure, i.e. pressure corresponding to χ = 1, results in Pinst = 80 barg. This value is above the ESP suction pressure, then causing the asphaltene to precipitate and increase emulsion stability, leading to deposits inside the pump. Therefore ESP suction pressure should be selected in relation to asphaltene instability pressure. Therefore, if the above approach had been adopted, some of the problems could be mitigated, by reducing operating costs, too. It is also possible to better estimate the risk of a failure as a result of the increased power demand to the motor. In fact, it is possible to obtain the trend of relative viscosity at the temperature of the reservoir, ηr, by mimicking in laboratory the energy addition of the ESP.
Table 1. Parameters for Equation 5 meaning
CASE STUDY
A case study, about an oilfield in the Middle East and North Africa (MENA) region, is presented here showing the approach that we are proposing to limit or even avoid some of the issues currently faced. This case was selected as a result of the observed high natural tendency to form stable emulsion and instability of asphaltene, which are improving the stability of the formed emulsions. Crude oil characteristics are summarized in Table 2.
The meaning of symbols, together with adopted values, is in Table 1; with these values, the resulting maximum droplet diameter is 9 × 10−6 m.
symbol
Article
(6)
where γ̇ is the shear rate but ε is also related to the power consumed over the total mass of emulsion being mixed, so that the viscosity and absorbed power are proportional. Thus, an increase in viscosity, as a result of emulsion formation and droplet resizing, would require additional power from the electrical motor to keep producing the desired flow rate. This continuous increase ultimately would exceed the design limits of the motor, causing a rupture in a very short time. E
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 8. Viscosity versus temperature at a shear rate of 20 s−1 for the oil sample in anhydrous conditions (blue) and in the presence of natural emulsion (red).
Table 3. Reservoir Properties
Table 4. WC and Mixing Time Effects
property
unit
value
WC (%, w)
mixing time (min)
relative viscosity
initial reservoir pressure reservoir temperature bubble pressure @ tres specific gravity @ res. conditions
psia °C psia −
3200 90.5 915 0.8221
0 0.4 0.4
0 1 3
1.00 7.89 12.18
flow in a rotating device can have a strong effect on the emulsion structure and viscosity. Moreover, laboratory tests showed after, 1 min of stirring, ηr at 40 °C was ca. 110. This value is in accordance with the relative viscosity measured (ηr = 138) in the same conditions on site (see Figure 8; oil with 42% WC curve) for the oil well considered in this case study. Then, it seems that 1 min of stirring is enough to mimic fluid dynamic conditions in the adopted ESP: by performing similar tests with various WCs, it would be possible to have information on the evolution of viscosity of the stream along the production life of the field. These values should be used to check the adequacy of the motor of the ESP to handle the produced fluids over time. There will be a time where the viscosity of the fluid will require a power higher than the power of the current motor, leading to its failure.
To quantify the effect of shear field on the system, a few rheological tests have been performed on the following samples: (1) anhydrous oil and (2) oil with 40% WC. The effect of stirring on the oil + water system has been studied by stirring the sample over time. The experimental procedure is described in the Appendix. Measured ηr shows an increase over the mixing time (Table 4), where the experimental data gathered have been scaled to the temperature of the reservoir. The results from laboratory tests are coherent with previous considerations about droplet size effects over viscosity. The estimated value of the droplet size (from eq 5) for the 1 min stirred sample results in 2.6 μm, while the 3 min stirred result is 1.4 μm (using the equation from ref 28). This suggest that the
Figure 9. Asphaltene stability map. F
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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this case, adequate overdesign of the power of the motor is needed to meet the increased power demand as a result of increased viscosity. Ultimately a costs/benefits analysis should be performed to check if increased costs of the ESP and its motor, as a result of the higher overdesign, are compensated by the increased amount of produced fluid. Further step in ESP design and manufacturing could be made considering the following topics:34 (1) Study (together with the manufacturers of pumps) geometries in which fluids are subjected to lower shear rates. (2) Provide the plant for injection of asphaltene stabilizers. Maybe it would be possible to design an “ad hoc” pump, already equipped for continuous injection of an additive. (3) Provide the plant for injection emulsion breakers. Maybe it would be possible to design an “ad hoc” pump, already equipped for continuous injection of an additive.
Figure 10. Relative viscosity (ηr) at the reservoir temperature over the mixing time.
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DISCUSSION AND CONCLUSION ESPs are employed as an artificial lift method to increase the production flow rate of a well. By doing this, downhole dynamic pressure is lowered (see Figure 11). If the new downhole pressure is lower than the pressure of the asphaltene precipitation onset and a non-zero WC is present, a strong w/o emulsion may form. This emulsion is stabilized by asphaltene and solids, which prevent drop coalescence and water separation. The droplet size is determined by geometry and kinematics, and it is likely that conditions (very small thickness, high shear rate, and high volume power) are such that a very small droplet is generated. This droplet size corresponds to a huge overall viscosity and then to huge head losses. In these conditions, pump motors can easily overheat and burn because the design conditions are overpassed, leading to the need of replacement, with expensive costs. At present, we propose the following verification to assess in advance the foreseen problems and to overcome them: (1) In the design of an ESP installation, verify the asphaltene deposition tendency of the produced fluid, evaluate in advance the asphaltene instability pressure, and, if possible, avoid pushing the process to excessively low pressures. (2) In the design of an ESP installation, be aware of the possibility of emulsion formation and verify in advance the changes in rheological properties under the same conditions of an ESP. In
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APPENDIX: EXPERIMENTAL PROCEDURE Fluid rheological behavior has been investigated in both anhydrous conditions and the presence of produced water (10 and 40%). Samples containing emulsified water have been prepared adding the desired amount of brine to anhydrous oil and mixing them using an IKA ULTRA-TURRAX T 25 digital at 3600 rpm for two different durations: up to 1 min and up to 3 min. Viscosity measurements of anhydrous and emulsified samples (obtained as described above) have been carried out at different temperatures (20−80 °C) in the shear rate range of 1−100 s−1 using a Haake Mars rotational rheometer equipped with a coaxial cylinder geometry (gap of 4.2 mm). Nomenclature
davg = average droplet diameter dmax = maximum droplet diameter D = impeller diameter N = rotating speed R = gas constant T = absolute temperature P = pressure Pins = instability pressure
Figure 11. Effect of the ESP insertion on the characteristic point. G
DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
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X = solvent/sample ratio (by weight or by volume) Y = paraffin/sample ratio (by weight or by volume) δi = solubility parameter of component i ϕ = volume fraction of water in oil ε = dissipation energy γ = interfacial tension γ̇ = shear rate ηc = viscosity of the continuous phase ηemulsion = viscosity of emulsion ηoil = viscosity of crude oil ηr = relative viscosity ρc = density of the continuous phase ρo = density of crude oil χ = solute−solvent interaction parameter ΔG = free energy
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AUTHOR INFORMATION
Corresponding Author
*Telephone: +39-02-520-59048. E-mail: sebastiano.correra@ eni.com. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The contribution in this work by Ferdinando Marfella, eni/ TEOP, is gratefully acknowledged. REFERENCES
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DOI: 10.1021/acs.energyfuels.5b02083 Energy Fuels XXXX, XXX, XXX−XXX
