Gas Solubility Measurement in Heavy Oil and Extra Heavy Oil at Vapor

Apr 1, 2013 - One is coming from Canada, and the other is coming from Venezuela. The experiments were conducted by adding solvent into the oil and ...
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Gas Solubility Measurement in Heavy Oil and Extra Heavy Oil at Vapor Extraction (VAPEX) Conditions Guillaume Varet,†,‡ François Montel,‡ Djamel Nasri,† and Jean-Luc Daridon*,† †

Laboratoire des Fluides Complexes et leurs Réservoirs, Faculté des Sciences et Techniques, UMR 5150, Université de Pau, BP 1155, 64013 Pau Cedex, France ‡ Centre Scientifique et Technique Jean Féger (CSTJF), TOTAL SA, Avenue Larribau, 64018 Pau Cedex, France ABSTRACT: A pressure−volume−temperature (PVT) cell has been developed for measuring light gas solubility in heavy oils and bitumen under pressure. It uses a magnetic stirrer designed to stir the fluid in a laminar way within oil with a viscosity up to 55 000 cP. Because of this stirring system, recombination of heavy oil and gas is achieved in less than 2 h. The apparatus was used to quantify the solubility of carbon dioxide and methane in two heavy oils. One is coming from Canada, and the other is coming from Venezuela. The experiments were conducted by adding solvent into the oil and recombining the system by pressurization with a full laminar stirring. Finally, solubility data were obtained by measuring the bubble pressure of the recombined fluid. This was achieved by determining the change of the PV slope during an isothermal decompression. Measurements were performed for various contents of gases and different temperatures ranging between 293 and 353 K.

1. INTRODUCTION The growth in oil demand leads to the development of alternatives to conventional oil and gas reserves. Among those alternatives, heavy oils along with bitumen appear as a potential source. The huge reserves of heavy oil mainly located in Canada and Venezuela can provide a substantial resource of hydrocarbon compounds in the next few decades if it can be extracted and upgraded with a good overall efficiency. From a physical point of view, heavy oils are characterized by a high mass density [American Petroleum Institute (API) gravity less than 20°] and a high viscosity (1 Pa s or greater). The extremely high viscosity of low-gravity oil made production difficult, and oil recovery with conventional methods rarely exceeds 10% in extra heavy oil fields. Consequently, extraction and production of heavy oil currently require special enhanced oil recovery processes, which drastically affect the production rate and cost of exploitation. These processes aim at reducing the viscosity of the crude oil and improving its mobility. This can be achieved by either heating the oil (steam injection1−3) or diluting the oil with light components (vapor extraction4−6). Thermal processes using steam heating are generally applied to enhance oil recovery because they provide both heat that reduces the viscosity and vapor that improves the oil drainage. However, the large heating requirement in addition to the treatment of water can make these heating processes uneconomical and result in major greenhouse gas emissions and environmental damage. Considering the vapor extraction (VAPEX) process instead of steam heating may improve the energy efficiency of recovery processes and may reduce the environmental damages. Various light alkanes (methane, ethane, and propane) can be taken into consideration for improving the displacement of heavy oils in non-thermal recovery techniques.7−9 Carbon dioxide can also be considered as a solvent or as a part of the solvent in the VAPEX process.10,11 Use of this gas can reduce greenhouse gas emissions in addition to improving oil recovery. Liquid solvent injection may also be used in addition to steam heating to improve the efficiency of © 2013 American Chemical Society

thermal processes and to reduce the energy consumption. The solubility of light components in heavy oil is an important consideration for choosing the solvent and designing and optimizing oil recovery processes based on vapor extraction because it contributes to viscosity drop off and oil swelling that both improve oil mobility. The heavy oil recovery performances are directly related to the amount of solvent dissolving into the oil. This property can be estimated using predictive models based on the equation of state or correlations.12,13 However, because of the high complexity of the chemical composition of crude oils, it is usually preferable to tune these models with a limited number of experimental data instead of using it in a pure predictive way. Consequently, measurements of gas solubility must be carried out in each specific sample of heavy oil. Because gas solubility corresponds to phase equilibrium data, the direct method commonly applied to determine the solubility of gases in a liquid consists of saturating the liquid with gas at the wanted conditions of pressure and temperature and then analyzing its composition. In this static analytical method, a small amount of liquid must be withdrawn from the equilibrium cell at a fixed pressure for analysis.14−16 However, for heavy oil and bitumen, the high viscosity of the fluid prevents easy sampling of crude under pressure. Consequently, for such a kind of system, it is better to use an indirect method that does not involve liquid sampling. This can be achieved using a static non-analytic method that consists of measuring the respective volumes of liquid and vapor phases in equilibrium17,18 or using a synthetic technique in which the phase transition of a known composition mixture is measured instead of the direct equilibrium conditions.19,20 This method rests on the determination of the onset of gas liberation from a homogeneous liquid phase during a volume expansion at a Received: February 14, 2013 Revised: March 30, 2013 Published: April 1, 2013 2528

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constant temperature. In dark systems, such as heavy oils, the conditions at which phase separation starts must be assessed indirectly. This determination can be carried out by varying pressure at a constant temperature and noting a break in the pressure versus volume curve corresponding to a change in the slope of the P−V curve of the fluid and, thus, to its compressibility. One of the main difficulties in using this pressure−volume−temperature (PVT) technique with heavy oil is related to the tricky task of mixing efficiently and rapidly a high viscous mixture of heavy oil and gas under pressure to keep the system in equilibrium. In the absence of stirring, mixing occurs via molecular diffusion, and the mechanism to reach equilibrium by the sole gas pressurization is extremely slow. Consequently, recombination of oil and gas is a long time coming. Moreover, without agitation, gas liberation also appears as a slow process21 and large error in bubble pressure measurement may occur because of liberation time delay during depletion experiments. At the opposite, strong mechanical stirring may produce dispersed gas bubbles into the oil, thus leading to the formation of foamy oil, whose properties drastically differ from recombined oil.22−24 To overcome this drawback, linked to the kinetics of gas dissolution in viscous liquids, an experimental apparatus was designed and patented25 to stir rapidly and efficiently mixtures of heavy oil and gas under pressure. The technique rests on a lamination stirring process that enhances the mixing efficiency by increasing the ratio of the contact surface/fluid volume. To achieve such stirring, a moving body of shell shape is alternatively shifted into an autoclave hollow cylinder with a small annular gap between the internal wall of the PVT cylinder and the moving body. When the body moves, both the heavy oil and gas are displaced backward, forcing them to flow through the annular layer where the contact area between oil and gas increase. This approach allows for mixing heavy oil and gas within short time scales and avoids the formation of stable gas bubbles during stirring. Finally, use of lamination stirring promotes the liberation of gas during the pressure drop and enables a rapid determination of the bubble pressure by pressure scanning. The capacity of the technique was tested by measuring the solubility of carbon dioxide and methane in a heavy oil from Venezuela and a bitumen from Canada for pressure up to 20 MPa and for different temperatures ranging between 293 and 353 K.

Figure 1. PVT cell: (1) plug, (2) magnetic ball, (3) external magnetic system, (4) magnetic system cache, (5) high-pressure variable volume cell, and (6) mobile piston. internal diameter of 20 mm and a length 200 mm that leads to a working volume of approximately 50 cm3. The stir element is made from neodymium iron boron (NdFeB), which is the most powerful of the permanent magnetic materials. The rare earth neodymium magnets have a higher magnetic field strength but have unfortunately a lower Curie temperature than any other types of magnets. Its maximum energy product (BHmax) is 350 kJ/m3, whereas it is only 30 kJ/m3 for common ferrite magnets. This is the only material that allows for moving the stirrer in extra viscous oil for magnetic strength. Its maximum operating temperature is limited to 100 °C. This temperature is sufficiently high for VAPEX conditions. For higher temperature experiments when viscosity of heavy oil is lower, NdFeB can be substituted with samarium cobalt materials that can work up to 350 °C but with a lower BHmax (200 kJ/m3). A spherical shape was considered for this stirrer because the magnetic fields of sphere magnets are concentrated more at the poles than other shapes. Its surface was coated with a thin film to protect neodymium from the fluid to be stirred. The stir element is shifted magnetically along the PVT cell caused by an external magnet assembly, which surrounds the cell. This magnet assembly consists of two annular magnets combined with three mild steel coils, as shown in Figure 2. As for the stir element, the annular magnets are made from NdFeB. The poles of each annular disc are alternated to magnetically bond the assembly. In this configuration, the system generates a holding force that is significantly stronger than those of an individual donut magnet. Moreover, the system concentrates it magnetic strength around the magnetic assembly. In this way, it can be used to hold and drive the stir element inside the cell. To keep the maximum magnetic coupling between the internal stirrer and the external driving system, the interstitial space between both elements must be reduced to a minimum. This interstice corresponds to the thickness of the cell wall in addition to the air gap between the external face of the cell and the external magnet as well as the fluid gap between the stirrer and the internal face of the cylinder. The thickness of the cell wall was set to 3 mm with an internal diameter of 20 mm in such a way as to achieve a maximum working pressure of 20 MPa. The air gap between the cell and the external magnet was fixed to 0.5 mm to allow for an easy longitudinal moving of the external magnet. Finally, the interstice between the stir element and the internal face of the cell was set to 0.5 mm. This gap constitutes an acceptable compromise between lower gaps that increase mixing efficiency but increase viscous strength, acting against the shifting of the stirrer and the high gap, which allows for an easier movement of the stirrer in viscous oil but reduces the laminar mixing efficiency. This gap as well as the magnetic assembly dimension was determined to move the stirrer into an oil with a viscosity of 55 000 mPa s by doing a simulation of both the fluid flow around the stirrer (polyflow) and the magnetic coupling between both magnet elements (Figure 3) [finite element method magnetics (FEMM)]. To stir the full fluid sample inside the cell,

2. EXPERIMENTAL SECTION The key point in performing the gas solubility measurement in heavy oil is to succeed in stirring efficiently and mixing rapidly viscous oil with gas under pressure. Commonly used mixing devices consist of a rotating body (helical) fully immersed in the fluid, and improvement of stirring is typically achieved by increasing the agitator speed. However, raising the speed of the mechanical agitation in a heavy oil−gas mixture may involve the formation of small gas bubbles. Because of the turbulent mixing, these bubbles disperse into the oil and form stable foamy oil, instead of blending and homogenizing liquids and gases. Moreover, increasing the rotating speed of the agitator does not guarantee that all of the fluid take part in the flow. Some stagnant volumes can only be partially stirred or even not at all. Thus, to carry out an efficient mixing that handles the large viscosity difference between heavy oil and gas, two issues must be solved: avoid the formation of stable gas bubbles, and minimize the stagnant volume where the fluid is not agitated. To meet the first requirement, it is necessary to create a laminar mixing that gently increases the interfacial area without breaking up the gas into bubbles. With the aim to produce such a lamination stirring during PVT experiments, an apparatus has been specially designed and patented.25 It is primarily composed of a high-pressure cell (Figure 1) made up of a vertically oriented non-magnetic (stainless-steel 316L) cylinder containing a movable body acting as a stirrer. The cylinder has an 2529

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satisfactory thermal uniformity within the cell and the fluid, the full experimental device was immersed in a thermoregulated bath with a stability of 0.02 K in the temperature range investigated (Figure 4). The main goal of this new device is to reduce the recombination time of extra heavy oils and light components. With a classical cell, the homogenization time is very long and blending achievement is not guaranteed when the stirring operation is stopped. With the aim to determine the capacity of the technique to recombine oil and gas systems, first, tests were performed on two different gases, carbon dioxide and methane, and different dead oils. These include a bitumen from Athabasca and heavy oil from Venezuela. The samples come from pilot plants and were filtered and dehydrated. The water content measured by Karl Fischer is less than 0.05% in weight. The compositions of these crudes, apart from their heavy fraction C30+, were determined by gel permeation chromatography and gas chromatography and summarized in Table 1.The average molecular weight as well as the relevant physical properties (density, API gravity, and viscosity at 323 K) of the crudes were also given in Table 2. Finally, the saturates, aromatics, resins, and asphaltenes (SARA) analysis carried out to determine the repartition SARA components in the heavy crude oils was listed in Table 2. To perform these analyses, the crude oils were first topped at 50 °C and 20 mbar to remove light ends (C15−). The resulting fraction was analyzed in an Iatroscan instrument to quantify the saturate, aromatic, and polar fractions (resin + asphaltene). Saturates were eluted with nheptane, whereas aromatics were eluted using a solvent composed of 25% (vol %) dichloromethane and 75% heptane. In addition, the asphaltene content was determined by precipitation using n-pentane as the precipitant agent with a weight/volume ratio of 1:40. Carbon dioxide (99.9 wt % purity) and methane (99.9 wt % purity) used in these measurements were supplied by Messer France.

Figure 2. Magnetic assembly: (1) annular earth rare magnets and (2) mild steel coils.

3. RESULTS AND DISCUSSION All of the tests were performed following the same procedure. The heavy oil is first put into a small volumetric pump, where it is heated to 333 K. At this temperature, it is transferred to the measurement cell under vacuum. The exact mass of liquid introduced during this process was determined by weighing by means of a high-weight/high-precision balance having a maximum weighing capacity of 2000 g with an accuracy of 10−3 g (Sartorius brand). While keeping the temperature of the oil at 333 K, the gas is added under pressure. With this aim in view, the gas was initially loaded at a saturation pressure in an aluminum reservoir tank (Gerzat brand) fixed on the plate and connected to the measuring cell through a flexible high-pressure capillary. The injected quantity is determined by weighing the reservoir tank during the filling using the same balance as for liquids. When all of the wanted quantity of gas is injected, the system is pressurized at the maximum pressure of 20 MPa and the to-and-fro movement of the stirrer starts. At this stage, two methods were tested and compared. The first rests on both an isochoric and isothermal process, in which the pressure is monitored as a function of time, as illustrated in Figure 5, in the case of Athabasca bitumen and 20% CO2. As seen in this figure, the pressure decreases drastically at the beginning of the experiment, meaning that the dissolution takes place efficiently because of the laminar stirring. A plateau is reached after a short time point at the end of the dissolution process. The second method tested consists of keeping constant the pressure at its maximum value by moving the piston during an isothermal process. By plotting the volume of the system as a function of time (Figure 6), it can be observed that the volume decreases rapidly to a constant value, corresponding to a stable state. This stable state representative of the thermodynamic equilibrium is achieved in a short time. The time needed to recombine oil and gas appears similar for both methods. However, the second method is preferred because it allows us to work at a higher

Figure 3. Modelization of the magnetic field of the homogenization system by FEMM. the stirring system is moved from one end to the other by means of a worm drive bound to the external magnetic system, with a go back in 1 min. The cell contains at one end a movable piston with a hemispheric shape at its extremity to minimize the quantity of oil that does not take part in the laminar mixing. A low-gear revolution-counter system is bound to the piston to read its position accurately (2 × 10−3 mm) and, therefore, to measure the volume change into the cell. The other end is closed by a plug with a hemispheric shape inside the cell. Four holes were machined in the plug. One hole at the top is connected by means of a valve to a vacuum pump or to the gas injection device. The second hole, at the bottom, is used for the inlet oil. The third hole is used to measure the pressure. A pressure transducer (Dynisco brand) inserted in this hole is directly in contact with fluid to reduce the dead volume. Because this pressure transducer is placed inside the cell, it is subject to the change of the temperature and needs to be calibrated as a function of the temperature. This calibration was performed in the full temperature range using a dead weight gauge (Bundenberg brand), with an accuracy better than 0.02% in the full pressure range (0.1−20 MPa). Finally, the last hole allows for the passage of a Pt100-type temperature probe used to measure the temperature of the fluid into the cell. To ensure 2530

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Figure 4. Schematic diagram of the apparatus used in this work: (1) temperature probe (Pt100), (2) pressure transducer, (3) thermoregulated bath, (4) stepper motor, (5) displacement system, (6) worm drive, (7) counter, (8) piston, and (9) high-pressure variable volume cell.

show recombination if enhanced using the laminar stirring technique. Therefore, the apparatus can be used to perform isopleth experiments to measure the saturation pressure and, consequently, the gas solubility. By such a technique, the saturation pressure of the heavy oil + gas system is estimated with an error less than 0.1 MPa. This error takes into account the uncertainty of the pressure gauge measurement as well as the error in the evaluation of the intersection point. These measurements were repeated for several temperatures ranging between 293 and 353 K. The saturation pressures measured by this way are reported in Table 3 for carbon dioxide and Table 4 for methane. From these data, P−X curves can be drawn at a fixed temperature. The resulting diagrams are plotted as an example in Figure 8 for carbon dioxide and Figure 9 for methane. It can be seen that solubility of both gases in both crudes increases with an increasing pressure at a constant temperature and decreases with an increasing temperature at a given pressure. Carbon dioxide has a high solubility in comparison to methane in the same P and T conditions. Moreover, the solubility of carbon dioxide is more affected by the temperature than that of methane (Figure 10), which decreases linearly with a small slope. Finally, a comparison of gas solubility in both oils reveals the same behavior with a difference between both sets of curves that comes from the difference in the molecular weight of the oils (Figure 11). To reduce the influence

pressure and, consequently, to recombine systems with more gas content. To make sure that the full dissolution of gas is achieved at the plateau, the pressure of the system was reduced just after reaching the plateau by increasing the volume step by step and measuring the pressure. During this expansion, the system was continuously stirred. The pressure was measured at each step and plotted as a function of the total volume (white triangle in Figure 7). A clear break can be observed on this curve, corresponding to the change in compressibility caused by gas liberation. The point at which the slope of the P(V) curve changes corresponds to the bubble point. It is determined accurately by interpolating three points below and three points above by a two linear function and noting their point of intersection. The experiment was repeated in a second run by starting the volume expansion before reaching the full recombination of oil and gas. The results of this second experiment are given in the same figure (black triangle). In this case, the pressure against the total volume curve does not exhibit any break. This continuous behavior is related to the expansion of a remaining gas phase when the decompression experiment starts before the full recombination is achieved. The recombination process was carried out for both oils, with several gas contents (in mol %) ranging from 20 to 60% for CO2 and from 15 to 40% for CH4 by gradually adding gas into the cell. In all cases, recombination was achieved in less than 2 h. These experiments carried out with both bitumen and extra oil clearly 2531

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Table 1. Chemical and Physical Properties of Crude Oils Used in This Work cut

bitumen (wt %)

C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30+ molecular weight (gmol) density at 15 °C (kg m−3) viscosity at 50 °C (cP)

0.058 0.123 0.065 0.051 0.065 0.221 0.627 0.937 1.292 1.459 1.645 1.954 2.055 2.149 2.078 2.132 2.040 1.961 1.925 1.813 1.926 2.054 1.749 69.615 541 1019.2 10000

heavy oil (wt %) 0.032 0.101 0.125 0.192 0.530 0.931 1.255 1.388 1.628 1.754 1.948 2.108 2.223 2.234 2.247 2.184 2.184 2.060 2.062 2.051 2.256 2.124 2.252 64.121 473

Figure 6. Change in volume during recombination of 80% Athabasca bitumen + 20% CO2 (in mol %) at a constant pressure.

12000

Table 2. SARA Analysis of Crude Oils Used in This Work heavy oil bitumen

saturates

aromatics

resins

asphaltenes

13.2 17.2

45.7 24.1

30.3 38.6

10.9 20.1

Figure 7. PV curve during decompression of a heavy oil + CO2 system: (white triangle) decompression starts after recombination is totally achieved and (black triangle) decompression starts before recombination is completely achieved.

Table 3. Saturation Pressures (MPa) Measured in Heavy Oil + CO2 Systems T (K) xCO2 (mol %)

293.15

313.15

333.15

353.15

2.1 5.2 7.1 10.2

6.0 8.5 12.2

3.0 5.3 7.3 9.7

3.5 6.4 8.8 11.8

Athabasca Bitumen 20.1 40.3 49.9 57.8 24.4 37.5 46.7 53.8

3.0 4.1 4.0 5.6 5.6 7.8 Venezuelan Heavy Oil 1.6 2.4 3.2 4.2 4.3 5.8 5.5 7.5

Figure 5. Evolution of pressure during recombination of 80% Athabasca bitumen + 20% CO2 (in mol %) at a fixed volume.

given temperature. Moreover, it can be seen that, for carbon dioxide, both sets of solubility curves overlap in this representation. This behavior that was already observed with CO2 in non-volatile pure solvents26 reveals that solubility of carbon dioxide follows a common behavior practically independent of the detailed composition of heavy oils within the pressure range investigated. On the basis of these results, the CO2 saturation pressure in heavy oil can be represented by a Henry’s law type model27

of the molecular weight of heavy oil, the mole fraction was converted to molality xgas 1000 mgas = xoilMoil (1) and the pressure is plotted as a function of molality (Figure 12). The result shows that, in this representation, the saturation pressure of both gases is practically proportional to solubility at a 2532

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Table 4. Saturation Pressures (MPa) Measured in Heavy Oil + CH4 Systems T (K) xCH4 (mol %)

293.15

313.15

Athabasca Bitumen 2.9 3.2 6.9 7.3 10.5 11.1 14.4 15.2 Venezuelan Heavy Oil 3.1 3.5 6.2 7.1 10.0 10.9 15.1 16.1

14.3 26.3 34.0 40.1 12.6 22.2 30.7 37.5

333.15

353.15

3.6 7.9 11.8 16.0

3.7 8.2 12.2 16.2

4.0 7.7 11.9 17.4

4.3 8.0 12.2 17.1

Figure 10. Gas solubility of Athabasca bitumen as a function of the temperature at 6 MPa: (blue square) CH4 and (white circle) CO2..

Figure 11. Comparison of gas solubilities in different oils at 33.15 K: (blue square) CH4 in Athabasca bitumen, (blue diamond) CH4 in Venezulean heavy oil, (white circle) CO2 in Athabasca bitumen, and (black triangle) CO2 in Venezuelan heavy oil at 353.15 K.

Figure 8. Carbon dioxide solubility in Athabasca bitumen as a function of the pressure along various isotherms: (white square) 293.15 K, (black diamond) 313.15 K, (white circle) 333.15 K, and (black triangle) 353.15 K.

Figure 12. Comparison of gas solubilities expressed in molality in different oils at 33.15 K: (blue square) CH4 in Athabasca bitumen, (blue diamond) CH4 in Venezuelan heavy oil, (white circle) CO2 in Athabasca bitumen, and (black triangle) CO2 in Venezuelan heavy oil at 353.15 K.

Figure 9. Methane solubility in Venezuelan heavy oil as a function of the pressure along various isotherms: (white square) 293.15 K, (black diamond) 313.15 K, (white circle) 333.15 K, and (black triangle) 353.15 K.

P=

mCO2 m°

HCO2

fugacity coefficient of the pure carbon dioxide. Values of HCO2 for each temperature were determined by least squares using both sets of data. The results are correlated to the temperature using the following relation: 4319 HCO2 = 17.0 − (4) T The prediction of this correlation was compared in Figure 13 to literature data reported for CO2 solubility in bitumen from four fields (Peace River,29,30 Athabasca,31,32 Cold Lake,33 and Wabasca34). The comparison indicates that the correlation fit with the data of the different crude oils within the experimental

(2)

where m° is a reference molality (1 mol kg−1) and HCO2 is a modified Henry’s constant that takes into account both liquidphase non-ideality and deviation to the ideal gas behavior.28

HCO2 =

kH,CO2γCO

2

* ϕCO

2

(3)

In this relation, kH,CO2 accounts for Henry’s constant, γCO2 is the activity coefficient written in terms of molality, and ϕ*CO2 is the 2533

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(5) Butler, R. M.; Mokrys, I. J. Recovery of heavy oils using vaporized hydrocarbon solvents: Further development of the VAPEX recess. J. Can. Pet. Technol. 1993, 32 (6), 56−62. (6) Butler, R. M.; Mokrys, I. J. Closed-loop extraction method for the recovery of heavy oils and bitumens underlain by aquifers: The VAPEX process. J. Can. Pet. Technol. 1998, 37 (4), 41−50. (7) Das, S. K.; Butler, R. M. Effect of asphaltene deposition on the VAPEX process: A preliminary investigation using a Hele−Shaw cell. J. Can. Pet. Technol. 1994, 33 (6), 39−45. (8) Das, S. K.; Butler, R. M. Diffusion coefficients of propane and butane in Peace River bitumen. Can. J. Chem. Eng. 1996, 74 (6), 985− 992. (9) Boustani, A.; Maini, B. B. The role of diffusion and convective dispersion in vapor extraction process. J. Can. Pet. Technol. 2001, 40 (4), 68−77. (10) Dunn, S. G.; Nenniger, E. H.; Rajan, V. S. V. A study of bitumen recovery by gravity drainage using low-temperature soluble-gas injection. Can. J. Chem. Eng. 1989, 67 (6), 978−991. (11) Torabi, F.; Yadali, J. B.; Stengler, B. M.; Jackson, D. E. The evaluation of CO2-based vapour extraction (VAPEX) process for heavyoil recovery. J. Pet. Explor. Prod. Technol. 2012, 2 (2), 93−105. (12) Kariznovi, M.; Nourozieh, H.; Abedi, J. Bitumen characterization and pseudocomponents determination for equation of state modeling. Energy Fuels 2010, 24 (1), 624−633. (13) Mehrotra, A. K.; Sarkar, M.; Svrcek, W. Y. Bitumen density and gas solubility predictions using the Peng Robinson equation of state. AOSTRA J. Res. 1985, 1 (4), 215−229. (14) Raal, J. D.; Muhlbauer, A. L. The measurement of high pressure vapour-liquid-equilibria part II: Static methods. Dev. Chem. Eng. Miner. Process. 1994, 2 (2−3), 88−104. (15) Ng, H. J.; Robinson, D. B. Equilibrium phase properties of the toluene−carbon dioxide system. J. Chem. Eng. Data 1978, 23 (4), 325− 327. (16) Laugier, S.; Richon, D. New apparatus to perform fast determinations of mixture vapor−liquid equmbria up to 10 MPa and 423 K. Rev. Sci. Instrum. 1986, 57 (3), 469−472. (17) Abedi, S. J.; Cai, H. Y.; Seyfaie, S.; Shaw, J. M. Simultaneous phase behavior, elemental composition and density measurement using X-ray imaging. Fluid Phase Equilib. 1999, 158 (1), 775−781. (18) Cai, H.-Y.; Shaw, J. M.; Chung, K. H. Hydrogen solubility measurements in heavy oil and bitumen cuts. Fuel 2001, 80 (8), 1055− 1064. (19) de Loos, T. W.; Pool, W.; Lichtenthaler, R. N. Fluid phase equilibria in binary ethylene + n-alkane systems. Ber. Bunsen-Ges. 1984, 88 (9), 855−859. (20) Pauly, J.; Coutinho, J. A. P.; Daridon, J.-L. High pressure phase equilibria in methane plus waxy systems1. Methane plus heptadecane. Fluid Phase Equilib. 2007, 255 (2), 193−199. (21) Upreti, S. R.; Mehrotra, A. K. Experimental measurement of gas diffusivity in bitumen: Results for CO2, CH4, C2H6, and N2. Can. J. Chem. Eng. 2002, 80 (1), 116−125. (22) Poindexter, M. K.; Zaki, N. N.; Kilpatrick, P. K.; Marsh, S. C.; Emmons, D. H. Factors contributing to petroleum foaming. 1. Crude oil systems. Energy Fuels 2002, 16 (3), 700−710. (23) Zaki, N. N.; Poindexter, M. K.; Kilpatrick, P. K. Factors contributing to petroleum foaming. 2. Synthetic crude oil systems. Energy Fuels 2002, 16 (3), 711−717. (24) Li, S.; Li, Z.; Lu, T.; Li, B. Experimental study on foamy oil flow in porous media with Orinoco Belt heavy oil. Energy Fuels 2012, 26 (10), 6332−6342. (25) Varet, G.; Daridon, J. L.; Nasri, D.; Montel, F. Mélange d’un fluide multiphase. Patent WO 2012123454, 2012. (26) Carvalho, P. J.; Coutinho, J. A. P. On the nonideality of CO2 solutions in ionic liquids and other low volatile solvents. J. Phys. Chem. Lett. 2010, 1 (4), 774−780. (27) Kumełan, J.; Kamps, A. P. S.; Tuma, D.; Maurer, G. Solubility of the single gases H2 and CO in the ionic liquid [bmim][CH3SO4]. Fluid Phase Equilib. 2007, 260 (1), 3−8.

Figure 13. Comparison of the correlation for saturation pressure (eqs 1 and 4) to literature data of CO2 solubility in bitumen: (red plus sign) Peace River at 353 K,29 (black triangle) Peace River at 350−352 K,30 (blue circle) Athabasca at 351−353 K,32 (white diamond) Cold Lake at 349−351 K,33 (black cross sign) Wabasca at 343−349 K,34 (solid line) correlation for 353.15 K, and (dashed line) correlation for 343.15 K.

uncertainty. This result confirms the common description of the solubility of CO2 in heavy oil and extra heavy oil. This common behavior cannot be extended to methane. However, CH4 saturation pressure in heavy oil can also be represented by a Henry’s law type model, with Henry’s constant specific to each crude oil studied. HCH4,bit = 26.34 −

4605 T

(5)

HCH4,HV = 22.45 −

3431 T

(6)

5. CONCLUSION In this work, we have analyzed the capacity of laminar mixing for recombining heavy oil and gas in an efficient way. A PVT cell containing a magnetic stirring system that can operate with high viscous oil has been implemented successfully. The apparatus that was tested here with a mixture of bitumen and carbon dioxide and methane can be used to measure the solubility of various light gases in extra heavy oils in the VAPEX conditions. Future work will be carried out to extend the apparatus to the measurement of thermophysical properties, in particular viscosity.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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REFERENCES

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