Selection of Optimal Solvent Type for High-Temperature Solvent

Article pubs.acs.org/EF

Selection of Optimal Solvent Type for High-Temperature Solvent Applications in Heavy-Oil and Bitumen Recovery A. Marciales and T. Babadagli* Department of Civil and Environmental Engineering, School of Mining and Petroleum Engineering, University of Alberta, Edmonton, Alberta T6G 2W2, Canada ABSTRACT: The selection of the most suitable solvent for an efficient heavy-oil recovery process is a critical task. Low carbon number solvents yield faster diffusion, but the mixing quality may not be high. Also, high carbon number solvents yield a better quality mixing (much less asphaltene precipitation), but the mixing process is rather slow. Hence, the understanding of solvent selection criteria for solvent-aided recovery processes has established two main aspects of oil−solvent (liquid−liquid) interaction: (1) oil−solvent mixture quality and (2) rate of mixture formation. Oil−solvent mixture quality is determined by two parameters: (1) viscosity and (2) asphaltene precipitation. The rate of mixing is quantified by the diffusion rate. Both mixture quality and mixing rate need to be quantitatively and qualitatively determined to select the suitable solvent for heavy-oil recovery. In addition to this, experiments that measure the solvent diffusion rate (and oil recovery) into a rock sample saturated with heavy oil at static conditions are needed to support the observations obtained from the liquid−liquid interaction of solvent and oil. This paper focuses on these tests and uses three oil samples with a wide range of viscosities (250−476 000 cP) and three liquid solvents with different carbon numbers varying between C7 and C13. Core experiments at different temperatures were performed on Berea sandstone samples using the same solvent−heavy oil pairs to obtain the optimum carbon size (solvent type)−heavy oil combination that yields the highest recovery factor and the least asphaltene precipitation. On the basis of the fluid−fluid (solvent−heavy oil) interaction experiments and heavy-oil-saturated rock−solvent interaction tests, the optimal solvent type was determined considering the fastest diffusion and best mixing quality for different oil−solvent combinations. solvent application at its dew point was suggested.4,21 On the other hand, it was found that significant asphaltene deposition may occur under these conditions.26,27 Then, heavier solvents in gas8,28,29 and liquid phase24 where found to be more convenient. The objective of this work is to propose solvent selection criteria based on their performance on the oil recovery rate and ultimate recovery from rock samples. To achieve this, sandstone samples saturated with three different heavy oils were exposed to solvent diffusion at static conditions at different temperatures and the recovery rate and ultimate recovery (and asphaltenes left behind), controlled by the diffusion rate and mixing quality,

1. INTRODUCTION After the pioneering works documented in the 1970s1−3 and the introduction of the vapor extraction (VAPEX) process,4 different versions of solvent-aided processes for heavy-oil recovery have been proposed.5−14 As a result of the high cost of the solvents, its industrial applications require a better understanding of solvent performance through extensive laboratory and computational efforts to optimize its use by minimizing its cost through maximized retrieval 15−17 and maximized oil recovery. 18−20 In this optimization process, the primary task is to select the proper solvent for given application conditions (temperature and injected amount), reservoir type, and oil composition.21−24 It is a well-known fact that lower carbon number solvents (typically propane and butane) yield a faster diffusion into oil and oil-saturated rocks.15,16 Therefore, higher carbon number solvents (from pentane up to C11−C15 carbon number range distillate oil) are more preferable for a better mixing, yielding higher ultimate recovery with less asphaltene deposition.24 However, with this type of “heavy” solvent, the diffusion rate is much slower compared to the “lighter” solvents. This requires a selection process that optimizes the recovery rate and ultimate recovery. Two critical properties of solvents need to be evaluated in solvent selection processes:25 (1) diffusion rate, the ability of a solvent to penetrate into the heavy oil, which will affect the oil recovery rate, and (2) mixing quality, the ability of a solvent to reduce oil viscosity, minimizing asphaltene precipitation, which will eventually affect the ultimate recovery. Attempts have been made to measure these two characteristics of oil−solvent pairs, and literature offers some insights on solvent preferences in heavy oil recovery. Initially, a low carbon number © XXXX American Chemical Society

Table 1. Oil Sample Properties oil sample

density at 25 °C (g/mL)

viscosity at 25 °C (cP)

refractive index, n, at 25 °C

mineral oil oil 1 oil 2 oil 3

0.8734 0.9818 1.0035 1.0156

250 20675 153000 476353

1.47635 1.55118 1.53835 1.58425

Table 2. Solvent Properties solvent

specific gravity

viscosity at 25 °C (cP)

refractive index, n, at 25 °C

heptane decane distillate

0.683 0.735 0.738

0.294 0.848 0.742

1.38418 1.40851 1.41025

Received: October 20, 2015 Revised: February 4, 2016

A

DOI: 10.1021/acs.energyfuels.5b02472 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

Figure 1. Boiling range distribution of oil samples and distillate. FBP = final boiling point.

Figure 2. (a) Berea sandstone core saturated with heavy oil. (b) Beginning of the solvent-soaking experiment. (c) Change in the color of the surrounding fluid (oil−solvent mixture) as a result of the diffusion process at soaking times of >150 h.

Table 3. Saturated Core−Solvent Experiments experiment number 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23

temperature volumeofsolvent/(°C) volume of oil 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 50 50

14.06 15.91 15.82 14.06 13.98 13.95 13.95 14.16 14.16 18.72 21.38 18.52 2.84 2.66 2.88 2.57 2.89 2.76 2.99 3.16 2.86 3.54 2.84

Table 3. continued

oil

solvent

mineral oil mineral oil mineral oil oil 1 oil 1 oil 1 oil 2 oil 2 oil 2 oil 3 oil 3 oil 3 oil 1 oil 1 oil 1 oil 2 oil 2 oil 2 oil 3 oil 3 oil 3 oil 1 oil 1

C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10

experiment number 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39

temperature volumeofsolvent/(°C) volume of oil 50 50 50 50 50 50 50 80 80 80 80 80 80 80 80 80

2.842 2.78 3.99 2.94 3.89 3.43 3.12 2.96 2.63 2.83 2.67 2.79 2.31 2.75 2.83 2.47

oil oil oil oil oil oil oil oil oil oil oil oil oil oil oil oil oil

1 2 2 2 3 3 3 1 1 1 2 2 2 3 3 3

solvent distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate C7 C10 distillate

respectively, were measured. Parallel to this work, the mixing quality and diffusion rates were also determined through viscosity measurements and “free” diffusion tests for the same oil and solvent pairs (liquid−liquid tests). From correlation of the results of these two types of tests (solvent−rock and liquid− liquid), the ideal solvent types, representing the optimal recovery B


Article

Energy & Fuels

Figure 3. (a) Cores and solvent heated to the settled temperature. (b) Core weight was measured. (c) Core and solvent placed in contact at the same temperature in a sealed imbibtion cell. (d) Soaking test was conducted at the determined temperature, and refractive index was taken periodically. (e) Final core was weighted at the end of the experiment.

Figure 7. Recovery rates for mineral oil: experiments 1−3.

Figure 4. Recovery rates for oil 1: experiments 4−6.

in our laboratories. Heptane and decane viscosities were obtained from the literature.31 Figure 1 shows the distillation curves and carbon size distribution for the oils and distillate solvent used in the experiments under their respective ASTM standards. The core saturation was accomplished through different steps. After the sandstone rock was cut, all of them were washed with sink water and dried at 140 °C in an oven inside a desiccator under vacuum for approximately 3 days. Subsequently, the cores were placed vertically in a container filled with its respective oil inside a closed desiccator connected to a vacuum line inside an oven settled at 75 °C. At this point, the weight was registered daily for about 1 week, and the process was stopped when the change in weight was less than 1%. Figure 2a shows a core saturated with heavy oil and its dimensions. A set of experiments, as listed in Table 3, were carried out at different temperatures by placing the core samples into a container filled with solvent for the soaking period. In all of the cases, the refractive index of the resulting mixture was measured periodically. Panels b and c of Figure 2 show the scheme for the set of the first 12 experiments carried out at room conditions, indicating the change in color of the solvent surrounding the core at the beginning and later times, respectively. For this case, a stirrer was used to homogenize the oil−solvent mixture before taking samples for refractometer readings. Figure 3 shows the procedure followed for the experiments step by step. For safety reasons, it was necessary to rotoevaporate the distillate employed in the experiments performed at 80 °C (experiment numbers 33, 36, and 39 in Table 3). Thus, this distillate would not have the hydrocarbon components with boiling point below 80 °C at atmospheric pressure compared to the original distillate in Figure 1. 2.2. Recovery Rate Evaluation by Refractive Index Measurement. The refractive index is defined as the ratio of velocity of light in a vacuum to the velocity of light in the substance (fluid). It is a dimensionless quantity and a temperature- and pressure-dependent quantity. The calculation of the refractive index for the hydrocarbon mixture is volume-based,30 and it eventually reflects the amount of solvent in the whole mixture. The oil volume fraction is calculated from the refractive mixture using the following equation: − nsolv n X vol−oil = mixture noil − nsolv (1)



rate and ultimate recovery, were determined for liquid solvents in the carbon number range of C7−C13 and heavy oil types with a viscosity range on different orders of magnitude.

2. EXPERIMENTAL METHODOLOGY 2.1. Materials and Experimental Procedure. Berea sandstone cores (ϕave = 22%, and kave = 500 md) with a diameter of 1.5 in. and 9.5 cm length were saturated with heavy-oil samples given in Table 1. Then, the cores were exposed to three different solvents detailed in Table 2. All oil sample properties and refractive indices were measured C


Article

Energy & Fuels

Figure 8. Recovery rates for cores saturated with oil 1 for experiments run at (a) 25 °C, (b) 50 °C, and (c) 80 °C.

Figure 9. Recovery rates for cores saturated with oil 2 with experiments run at (a) 25 °C, (b) 50 °C, and (c) 80 °C.

where Xvol−oil is the volumetric fraction of oil, nmixture is the refractive index of the mixture at 25 °C, nsolv is the refractive index of pure solvent at 25 °C, and noil is the refractive index of pure oil at 25 °C. This can be related to the recovery rates by applying the following relationship:

% RF = X vol−oil(Vtotal−mixture)/Voil initially inside the core

3. RESULTS Figures 4−7 show cumulative oil recovery for four oil types when the volume proportion of solvent/oil is high, which corresponds to the first 12 experiments in Table 3. In this set of experiments, distillate was found to have the highest oil recovery in all employed oil samples, except for oil 3. In the latter, heptane was found to be the best solvent. This could be explained by the lower diffusion rate of distillate in oil 3, which is the heaviest sample used in our experiments. 3.1. Temperature Effect. Figures 8−10 show the effect of the temperature on recovery curves for the experiments run at a low volume solvent/oil ratio and for nine different oil−solvent pairs. Panels a−c of Figure 8 display the change of the solvent behavior for the experiments run with oil 1. At room conditions (Figure 8a), distillate and heptane show similar results; however, at the end of the experiments, distillate reaches a slightly higher recovery. The difference between this pair of recovery curves is very distinctive when a high amount of solvent is employed (Figure 4). In the latter, distillate is more efficient than heptane. This could be attributed to the pore blocakage by asphaltenes on

(2)

where % RF is the recovery factor, Vtotal−mixture is the total volume of the mixture, and Voil initially inside the core is the volume of oil initially inside the core. When eqs 1 and 2 are applied, the following assumptions were made: (1) The total volume change of the system as a result of mixing is negligible. (2) The refractive index obtained from each sample obtained represents the average value of the mixture. (3) The volume of oil encountered inside the solvent phase is equal to the volume of solvent inside the porous media. At the end of each experiment, the obtained recovery factor through the refractive index was validated with the weight change of the core from steps e and b in Figure 3. Then, the ultimate recovery factor and recovery curves were obtained. The refractive index measurements and its comparison to the weighting method are provided in the Appendix. Also, the origin of the mixing rule is explained in detail in the Appendix. D


Article

Energy & Fuels

Figure 10. Recovery rates for cores saturated with oil 3 with experiments run at (a) 25 °C, (b) 50 °C, and (c) 80 °C.

Figure 11. Ultimate recovery summary.

components compared to oils 1 and 3 (the distillation curve has a higher slope in the 400−700 °C temperature range). Therefore, the addition of heptane in the presence of this oil would increase the chances of asphaltene precipitation compared to oils 1 and 3. The results achieved with oil 3 are shown in panels a−c of Figure 10. Oil 3 has less amount of heavier components than oil 2 (Figure 1) and does not have as many lighter components as oil 1 or 2 (this would explain its high viscosity). Then, its equilibrium was altered in the presence of heptane, yielding more asphaltenes compared to the case of mixing with distillate, as shown in Figure A6 of the Appendix. The higher the amount of asphaltenes precipitated on the core surface (as shown in panels a−c of Figure 15), the higher the chances of pore plugging. This leads to less available area for oil−solvent contact for mass tranfer. All of these phenomena would have a negative impact on oil recovery when heptane is employed and would help to understand why distillate shows better performance in general, confirming its greater ability to recover more oil and to provide a better mixture quality with heavy-component oil samples. Panels a−c of Figure 11 summarize the final recoveries measured at the end of the experiments based on the change of the weight of each core employed. In general, heptane and

the surface of the core when heptane was introduced. That is because the change in the concentration at the interface between the core and the solvent is high; this leads to a faster asphaltene deposition. For the experiments run at 50 °C (Figure 8b), the results were different; heptane showed better recovery than distillate. In this case, a higher temperature would decrease the asphaltene precipitation expectedly. Also, some components of the original distillate would be in the vapor phase, leading to a lower mixture quality. As mentioned earlier, the components with a boiling point below 80 °C were removed from the distillate used through the rotoevaporation process. This would change the results for 80 °C (Figure 8c), in which the distillate efficiency was better than heptane because both oil and solvent were in the liquid state and a better mixing occurred. Panels a−c of Figure 9 illustrate the results obtained with oil 2. Distillate was more efficient than heptane and decane at 25 and 80 °C, while at 50 °C, it barely showed higher recovery than heptane. The temperature effect on the quality of the mixture would be critical in the same way as observed for the oil 1 cases. In addition, the oil type would play a crucial role to influence the solvent performance. As illustrated in Figure 1, oil 2 has heavier E


Article

Energy & Fuels

run at 25 °C after a period surrounding 300 h. On the basis of the overall concentration of solvent employed in the soaking tests, its molecular diffusion rate was obtained and plotted for the data set in the x axes of panels a and b of Figures 12−14. These values were calculated from our earlier experiments that used the same oil−solvent pairs,25 as explained in the Appendix. Because the diffusion rate would eventually affect the oil recovery rate, each of the values found was paired with its ultimate recovery to evaluate the best solvent based on these two criteria. As a general rule, it was observed that the higher the concentration of solvent, the higher the diffusion rate and, hence, the higher the oil recovery.21 However, this increase was found not to be proportional in all cases in our study. Panels a and b of Figure 12 show close recovery values for oil 1 when our three solvents were used at a low concentration and had a small diffusion rate, but the difference in terms of ultimate recovery was greater when the solvent amount increased. For these cases, the distillate−heptane−decane decreasing production trend was kept in both cases and the diffusion rate was similar for the distillate and heptane. Panels a and b of Figure 13 show the values for oil 2. Here, again, the distillate−heptane−decane decreasing production trend was followed, but the distillate diffusion rate at a high solvent concentration is closer to decane than heptane. The results for oil 3 gave different trends. The distillate is more efficient than heptane if employed at a lower concentration, even though the diffusion rate is slightly higher (Figure 14a). This is in contrast to the high concentration case where heptane showed better efficiency (Figure 14b). Because the solvent was not replenished in these experiments, the soaking time effect in the solvent efficiency was tested experimentally to find how much would compensate for doubling the time of the runs when a low concentration of solvent was used or if the prolonged time of contact between the oil−solvent pairs would reach the same recovery as the high concentration cases in the long term. This is shown in Figures 12c, 13c, and 14c, with the numbers over the bars indicating the soaking hours. This result indicates that a longer solvent exposure leads to a higher recovery for most cases; however, doubling the time of the tests was not enough to reach the same recovery as if a higher concentration of solvent was employed in half the period of time. Nevertheless, a longer period of time than that employed here would eventually drive to this point. 3.3. Recovery Mechanisms. The main purpose of solvent injection in heavy-oil recovery processes is to reduce in situ oil viscosity.4,21 However, the success of this method depends upon the “driving force” or mass transfer between the solvent and oil inside the matrix,32,33 and hence, other forces, such as gravity and viscous forces, along with pure solvent diffusion may contribute to oil recovery at different regions in the same core. This would explain the appearance of the cores left behind after, e.g., the results of experiments 28−30 defined in Table 3 and shown in Figure 15. Panels a and b of Figure 15 show how organic material was deposited (mainly at the top of each sample). This is expected to be asphaltene because the solvents used in both cases are paraffinic, while this material was not observed in Figure 15c, where the distillate with high aromatic components was employed. It is also interesting to note that precipitated materials were observed mainly at the top of the rock samples, and the bottom part was swept better. As a result of the significant difference between the density of the solvent and oil employed, heptane and decane have a tendency to move up. This buoyancy effect caused more interaction of the solvents with oil, causing more asphaltene precipitation at the top of the samples. The solvent−oil mixture than moved down by gravity and convective

Figure 12. Solvent concentration and soaking time effect on experiments run at 25 °C for cores saturated in oil 1.

distillate reach higher recoveries than decane when experiments were run at 25 and 50 °C. Decane and distillate were the better options at 80 °C. Also, it was found that increasing the temperature from 25 to 50 °C improves heptane efficiency in all oil samples, and the recovery does not improve but even decreases when the temperature is raised and employed closer to its boiling point (80 °C) for oils 1 and 3, concluding that the best performance for heptane was accomplished at 50 °C for two of three oil samples. On the other hand, for the decane and distillate cases, the increase in the temperature increased the recovery. Finally, the distillate exhibited the highest recovery for each oil sample at all temperatures. The only exception was oil 1 at 50 °C (Figure 11a), which yielded an almost similar recovery to that of the distillate. 3.2. Solvent Concentration and Soaking Time Effects on Recovery. Figures 12−14 evaluate the solvent efficiency when this is used at low and high concentrations as well as the soaking time effect in the ultimate recovery for the experiments F


Article

Energy & Fuels


transport, yielding a better swept at the bottom, as also observed by Kahrobaei et al.32 and Hatiboglu and Babadagli.34 The analysis provided up to this point clearly indicates that the diffusion rate and mixing quality should be considered simultaneously in the selection of optimal solvent type and application procedure. The diffusion rate mentioned here refers to the molecular diffusion coefficient (liquid−liquid interaction of oil and solvent), and it may be extended to the effective diffusion coefficient (interaction of solvent with oil-saturated rock) as long as tortuosity is known.35 On the basis of the observations presented in this paper, starting the solvent treatment with light solvents (low carbon number) for a short period of time and continuing it with distillate type may yield technically and economically feasible processes. Note, however, that we used “liquid” solvents in the experiments, whereas “gas” solvents, such as propane and butane, are suggested5,6 in practice. Recent studies have shown that small carbon number solvents may yield inefficient mixing25,26,36 or low mixing quality (with high asphaltene precipitation), but midcarbon numbers are more efficient (hexane−heptane) and yield

optimal mixing quality. Therefore, it might be more preferable to start the process with this carbon number range (C6−C7) alkanes before switching to distillate.

4. CONCLUSIONS AND REMARKS Oil recovery rate by solvent diffusion was found to be dependent upon the diffusion rate at early stages of the experiments when the solvent concentration in the mixture (oil and solvent) surrounding the core was high. In this study, it was observed that a lower solvent concentration (half for instance) needs more exposure (soaking) time (more than twice) to compensate for the effect of a high amount of solvent to obtain the same oil recovery. The results showed that heptane yielded the highest recovery (diffusion) rate followed by the distillate and decane at early times. However, at late times, the distillate and heptane showed similar ultimate recoveries that can translate into a better mixing than decane. This could be explained by the aromatic content of the distillate that dissolves the heavier fractions more successfully than single-component alkanes. G


Article

Energy & Fuels


Figure 15. Cores saturated with oil 3 left after experiment at 50 °C were run in experiments (a) 28, (b) 29, and (c) 30.

The temperature, at which the liquid−liquid heavy oil/solvent mixture is formed, would possibly affect the ultimate recovery. For these experiments, because the oil and solvent were placed in contact at the same temperature, it was found that the closest the solvents are to their boiling points, the lower the recovery would be. Heptane optimum temperature application was found at

The distillate employed for these sets of experiments was found to be the most efficient solvent when both the diffusion rate and mixing quality were considered as well as the availability. However, it would be plausible to start the process with light singlecomponent solvents for a short period of time and continue with distillate-type (heavier) solvents for a better efficiency. H


Article

Energy & Fuels 50 °C, and the distillate gave good results when it is used all in the liquid phase (25 and 80 °C). Along with mass transfer as a result of solvent diffusion, it was found that gravity and viscous forces would enhance the recovery at the bottom of the cores because the buoyancy force would lead to a faster and better sweep section inside the oil matrix.

■

APPENDIX To generate the values of the x axes of panels a and b of Figures 12−14, we used our previous data given in Figures 9, 11, and 13 of Marciales and Babadagli.25 To measure the diffusion coefficients using these data, we obtained the profiles and calculated the values at room conditions (25 °C). Figures A1−A3 Figure A3. Molecular diffusion coefficient versus solvent concentration for oil 2 (modified with permission from Figure 18 of ref 25. Copyright 2014 Society of Petroleum Engineers).

Figure A1. Molecular diffusion coefficient versus solvent concentration for mineral oil (modified with permission from Figure 14 of ref 25. Copyright 2014 Society of Petroleum Engineers).

Figure A4. Precipitated asphaltene at different concentrations of solvent in oil 1 (data obtained with permission from ref 40. Copyright 2016 Society of Petroleum Engineers).

Figure A2. Molecular diffusion coefficient versus solvent mass fraction for oil 1 (modified with permission from Figure 16 of of ref 25. Copyright 2014 Society of Petroleum Engineers).

Figure A5. Precipitated asphaltene at different concentrations of solvent in oil 2 (data obtained with permission from ref 40. Copyright 2016 Society of Petroleum Engineers).

illustrate the replots of these three figures. The very beginning of the experiments with a high solvent concentration around the rock sample was taken to obtain the diffusion rates. As a result of the high solvent concentration around the rock sample, the diffusion rate is at its highest value. As seen in Figures A2 and A3, diffusion rates corresponding to ∼90% solvent concentration (mass fraction) were obtained (illustrated by the arrows) for three solvents. The solvent concentration value is 96% for the mineral oil cases (Figure A1), at which point the asymptotic behavior starts. The obtained diffusion coefficient values were used as the y axes of Figures 12−14. The amount of asphaltenes precipitated by each solvent was measured in the work by Marciales and Babadagli.25 These results were obtained after a series of titration tests as described in the literature.37−39 The results are displayed in Figures A4−A6.

Figure A6. Precipitated asphaltene at different concentrations of solvent in oil 3 (data obtained with permission from ref 40. Copyright 2016 Society of Petroleum Engineers). I


Article

Energy & Fuels Table A1. Refractive Index versus Experimental Data for Heptane−Oil 1 Mixtures heptane−oil 1 g of C7/g of oil

Xw C7

X v C7

n-exp at 25 °C

n-clc at 25 °C

0 0.194162 0.398779 0.602055 0.857804 1.422569 2.737251 4.145267 5.648683

0 0.162592 0.285091 0.375802 0.46173 0.587215 0.732424 0.805647 0.849594 1

0 0.218028 0.364131 0.46368 0.551934 0.671358 0.79719 0.85617 0.890249 1

1.551180 1.55181 1.49276 1.47626 1.46145 1.43849 1.41624 1.40747 1.40057 1.38418

1.55118 1.514769331 1.490370131 1.473745519 1.45900699 1.439063253 1.418049294 1.408199636 1.402508354 1.38418

100% SHHO 0.2 mL of ste/g of oil 0.4 mL of ste/g of oil 0.6 mL of ste/g of oil 0.8 mL of ste/g of oil 2 mL of ste/g of oil 4 mL of ste/g of oil 6 mL of ste/g of oil 8 mL of ste/g of oil

Table A2. Refractive Index versus Experimental Data for Decane−Oil 2 Mixtures decane−oil 2 g of C10/g of oil

Xw C10

Xv C10

n at 25 °C

n-clc at 25 °C

0 0.199488 0.394562 0.596947 0.793034 1.47025 2.94 4.393251 5.572783

0 0.166311 0.282929 0.373805 0.442286 0.595183 0.746193 0.814583 0.847857 1

0 0.214372 0.349831 0.446837 0.520213 0.657616 0.793807 0.848829 0.876465 1

1.54322 1.506665 1.48932 1.47585 1.47115 1.44698 1.4359 1.42895 1.41969 1.40492

1.54322 1.513572 1.494838 1.481422 1.471275 1.452272 1.433436 1.425827 1.422005 1.40492

100% cumm 0.2 g of C7/g of oil 0.4 g of C7/g of oil 0.6 g of C7/g of oil 0.8 g of C7/g of oil 2 mL of C7/g of oil 4 mL of C7/g of oil 6 mL of C7/g of oil 8 mL of C7/g of oil

components were simplified to two, the oil and the solvent. After application of the Kay equation, xi would result in the volume fraction of the oil in the mixture (as described in eq 1).

Table A3. Refractive Index versus Weighting Method To Measure Oil Recovery

■

oil recovered (%) experiment number

by weight method (g)

by refractive index

22 23 24

67.30 42.95 64.58

63.66 41.90 64.80

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

■

Reliability of the Measurements

For the sake of the reliability of measurements, we tested the refractive index measurements against weight measurements. The results of refractive index measurements for two oil types are given in Tables A1 and A2. A comparison of both methods (refractive index and weight method) is shown in Table A3. Although they are highly close to each other, we consider the mass balance (weight methods) more reliable because the measurements are easier to repeat, while the refractive index measurements are highly sensitive to the loss of any light component during the measurements.

ACKNOWLEDGMENTS This research was conducted under T. Babadagli’s Natural Sciences and Engineering Research Council of Canada (NSERC) Industrial Research Chair in Unconventional Oil Recovery (industrial partners are CNRL, SUNCOR, Petrobank, Sherritt Oil, APEX Eng., PEMEX, Husky Energy, and Statoil). Partial support was also obtained from a NSERC Discovery Grant (RES0011227). The authors gratefully acknowledge these supports. This paper is a revised version of SPE 170021 presented at the SPE Heavy Oil Conference held in Calgary, Alberta, Canada, June 10−12, 2014.

Origin of the Refractive Index Mixing Rule

■

The oils employed in the experiment are multicomponent samples. Then, the simplest and practical mixing rule applicable is the Kay mixing rule30

REFERENCES

(1) Farouq Ali, S. M.; Snyder, S. G. Miscible Thermal Methods Applied to a Two-Dimensional, Vertical Tar Sand Pack, With Restricted Fluid Entry. J. Can. Pet. Technol. 1973, 12 (04), 22−26. (2) Allen, J. C.; Redford, D. A. Combination Solvent-Noncondensable Gas Injection Method for Recovering Petroleum from Viscous Petroleum-Containing Formations Including Tar Sand Deposits. U.S. Patent 4,109,720 A, Aug 29, 1978. (3) Farouq Ali, S. M.; Abad, B. Bitumen Recovery from Oil Sands, Using Solvents in Conjunction with Steam. J. Can. Pet. Technol. 1976, 15 (03), 11.

i=1

θm =

AUTHOR INFORMATION

Corresponding Author

∑ xiθi N

where θm is the property of the mixture with N components, θi is the property of the pure component i, and xi is fraction of component i in the mixture. Becaus the refractive index is a volumetric-based mixing rule, xi should be defined as the volume fraction. Then, during the experiments, the number of J


Article

Energy & Fuels

(24) Naderi, K.; Babadagli, T.; Coskuner, G. Bitumen Recovery by the SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method: An Experimental Study on Grosmont Carbonates. Energy Fuels 2013, 27 (11), 6501−6517. (25) Marciales, A.; Babadagli, T. Solvent Selection Criteria Based on Diffusion Rate and Mixing Quality for Different Temperature Steam/ Solvent Applications in Heavy Oil and Bitumen Recovery. Proceedings of the SPE Latin American and Caribbean Petroleum Engineering Conference (LACPEC); Maracaibo, Venezuela, May 21−23, 2014; Paper SPE169291-MS, DOI: 10.2118/169291-MS. (26) Arciniegas, L. M.; Babadagli, T. Quantitative and Visual Characterization of Asphaltenic Components of Heavy-Oil and Bitumen Samples after Solvent Interaction at Different Temperatures and Pressures. Fluid Phase Equilib. 2014, 366, 74−87. (27) Arciniegas, L. M.; Babadagli, T. Asphaltene Precipitation, Flocculation and Deposition during Solvent Injection at Elevated Temperatures for Heavy Oil Recovery. Fuel 2014, 124, 202−211. (28) Ayodele, O. R.; Nasr, T. N.; Ivory, J. J.; Beaulieu, G.; Heck, G. Testing and History Matching ES-SAGD (Using Hexane). Proceedings of the SPE Western Regional Meeting; Anaheim, CA, May 27−29, 2010; Paper SPE-134002-MS, DOI: 10.2118/134002-MS. (29) Keshavarz, M.; Okuno, R.; Babadagli, T. Optimal Application Conditions for Steam-Solvent Coinjection. Proceedings of the SPE Heavy Oil Conference-Canada; Calgary, Alberta, Canada, June 11−13, 2013; Paper SPE-165471-MS, DOI: 10.2118/165471-MS. (30) Riazi, M. R. Characterization and Properties of Petroleum Fractions, 1st ed.; ASTM International: West Conshohocken, PA, 2005; ASTM Manual Series MNL50, pp 430. (31) Dymond, J. H.; Oye, H. A. Viscosity of Selected Liquid n-Alkanes. J. Phys. Chem. Ref. Data 1994, 23, 41−53. (32) Kahrobaei, S.; Farajzadeh, R.; Suicmez, V. S.; Bruining, J. GravityEnhanced Trasfer between Fracture and Matrix in Solvent-Based Enhanced Oil Recovery. Proceedings of the SPE Improved Oil Recovery Symposium; Tulsa, OK, April 14−18, 2012; Paper SPE-154171-MS, DOI: 10.2118/154171-MS. (33) Nenniger, J. E.; Dunn, S. G. How Fast is Solvent Based Gravity Drainage? Proceedings of the Canadian International Petroleum Conference; Calgary, Alberta, Canada, June 17−19, 2008; Paper PETSOC2008-139, DOI: 10.2118/2008-139. (34) Hatiboglu, C.; Babadagli, T. Diffusion Mass Transfer in Miscible Oil Recovery: Visual Experiments and Simulation. Transp. Porous Media 2008, 74 (2), 169−184. (35) Peters, E. Petrophysics; Live Oak Book Company: Austin, TX, 2012. (36) Arciniegas, L.; Babadagli, T. Optimal Application Conditions of Solvent Injection into Oilsands to Minimize the Effect of Asphaltene Deposition: An Experimental Investigation. Proceedings of the SPE Heavy Oil Conference-Canada; Calgary, Alberta, Canada, June 11−13, 2013; Paper SPE-165531-MS, DOI: 10.2118/165531-MS. (37) Kokal, S. L.; Najman, J.; Sayegh, S. G.; George, A. E. Measurement and correlation of asphaltene precipitation from heavy oils by gas injection. J. Can. Pet. Technol. 1992, 31 (04), 24−30. (38) Rassamdana, H.; Dabir, B.; Nematy, M.; Farhani, M.; Sahimi, M. Asphalt Flocculation and Deposition: I. The Onset of Precipitation. AIChE J. 1996, 42 (1), 10−22. (39) Buenrostro-Gonzalez, E.; Lira-Galeana, C.; Gil-Villegas, A.; Wu, J. Asphaltene Precipitation in Crude Oils: Theory and Experiments. AIChE J. 2004, 50 (10), 2552−2570. (40) Marciales, A.; Babadagli, T. Solvent Selection Criteria Based on Diffusion Rate and Mixing Quality for Steam/Solvent Applications in Heavy-Oil and Bitumen Recovery. SPE Reservoir Eval. Eng. 2016.

(4) Butler, A. M.; Mokrys, I. J. Recovery of Heavy Oils Using Vaporized Hydrocarbon Solvents: Further Development of the Vapex Process. J. Can. Pet. Technol. 1993, 32, 56−62. (5) Das, S. K.; Butler, R. M. Countercurrent Extraction of Heavy Oil and Bitumen. Proceedings of the International Conference on Horizontal Well Technology; Calgary, Alberta, Canada, Nov 18−20, 1996; Paper SPE-37094-MS, DOI: 10.2118/37094-MS. (6) Das, S. K.; Butler, R. M. Diffusion Coefficients of Propane and Butane in Peace River Bitumen. Can. J. Chem. Eng. 1996, 74, 985−992. (7) Nasr, T. N.; Beaulieu, G.; Golbeck, H.; Heck, G. Novel Expanding Solvent-SAGD Process “ES-SAGD”. J. Can. Pet. Technol. 2003, 42 (1), 13−16. (8) Nasr, T. N.; Ayodele, O. R. Thermal Techniques for the Recovery of Heavy Oil and Bitumen. Proceedings of the SPE International Improved Oil Recovery Conference in Asia Pacific; Kuala Lumpur, Malaysia, Dec 5− 6, 2005; Paper SPE-97488-MS, DOI: 10.2118/97488-MS. (9) Zhao, L. Steam Alternating Solvent Process. Proceedings of the International Thermal Operations and Heavy Oil and Western Regional Meeting; Bakersfield, CA, March 16−18, 2004; Paper SPE-86957-MS, DOI: 10.2118/86957-MS. (10) Zhao, L.; Nasr, T. N.; Huang, H.; Beaulieu, G.; Heck, G.; Golbeck, H. Steam Alternating Solvent Process: Lab Test and Simulation. J. Can. Pet. Technol. 2005, 44 (09), 37−43. (11) Li, W.; Mamora, D.; Li, Y. Light-and Heavy-Solvent Impacts on solvent-Aided-SAGD Process: A Low-Pressure Experimental Study. J. Can. Pet. Technol. 2011, 50 (04), 19−30. (12) Pathak, V.; Babadagli, T.; Edmunds, N. R. Heavy Oil and Bitumen Recovery by Hot Solvent Injection. J. Pet. Sci. Eng. 2011, 78, 637−645. (13) Pathak, V.; Babadagli, T.; Edmunds, N. R. Mechanics of Heavy Oil and Bitumen Recovery by Hot Solvent Injection. SPE Res. Eval. and Eng. 2012, 15 (2), 182−194. (14) Pathak, V.; Babadagli, T.; Edmunds, N. R. Experimental Investigation of Bitumen Recovery from Fractured Carbonates Using Hot Solvents. J. Can. Pet. Technol. 2013, 52 (04), 289−295. (15) Al-Bahlani, A. M.; Babadagli, T. Field Scale Applicability and Efficiency Analysis of Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method for Heavy-Oil Recovery. J. Pet. Sci. Eng. 2011, 78, 338−346. (16) Al-Bahlani, A.-M.; Babadagli, T. SOS-FR (Solvent-Over-Steam Injection in Fractured Reservoir) Technique as a New Approach for Heavy-Oil and Bitumen Recovery: An Overview of the Method. Energy Fuels 2011, 25 (10), 4528−4539. (17) Mohammed, M.; Babadagli, T. Efficiency of Solvent Retrieval during Steam-Over-Solvent Injection in Fractured Reservoirs (SOS-FR) Method: Core Scale Experimentation Proceedings of the SPE Heavy Oil Conference; Calgary, Alberta, Canada, June 11−13, 2013; Paper SPE165528-MS, DOI: 10.2118/165528-MS. (18) Edmunds, N.; Maini, B.; Peterson, J. Advanced Solvent-Additive Processes via Genetic Optimization. Proceedings of the Canadian International Petroleum Conference (CIPC); Calgary, Alberta, Canada, June 16−18, 2009; Paper PETSOC-2009-115, DOI: 10.2118/2009-115. (19) Al-Gosayir, M.; Leung, J.; Babadagli, T. Design of SolventAssisted SAGD Processes in Heterogeneous Reservoirs Using Hybrid Optimization Techniques. J. Can. Pet. Technol. 2012, 51 (6), 437−44. (20) Al-Gosayir, M.; Leung, J.; Babadagli, T.; Al-Bahlani, A. M. Optimization of SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method Using Hybrid Techniques: Testing Cyclic Injection Case. J. Pet. Sci. Eng. 2013, 110, 74−84. (21) Gupta, S.; Gittins, S.; Picherack, P. Insights into Some Key Issues with Solvent Aided Process. J. Can. Pet. Technol. 2004, 43 (02), 54−61. (22) Naderi, K.; Babadagli, T. Use of Carbon Dioxide and Hydrocarbon Solvents During the Method of Steam-Over-Solvent Injection in Fractured Reservoirs for Heavy-Oil Recovery From Sandstones and Carbonates. SPE Reservoir Eval. Eng. 2014, 17 (02), 286−301. (23) Naderi, K.; Babadagli, T. Solvent Selection Criteria and Optimal Application Conditions for Heavy-Oil/Bitumen Recovery at Elevated Temperatures: A Review and Comparative Analysis. J. Energy Resour. Technol. 2016, 138 (1), 012904. K


Selection of Optimal Solvent Type for High-Temperature Solvent

Recommend Documents