Effect of Temperature on Two-Phase Relative Permeabilities of

Table 1. Summary of Studies Addressing the Effect of Temperature on Relative Permeability Data .... Irreducible water saturation was found to increase...
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Effect of Temperature on Two-Phase Relative Permeabilities of Heavy Oil, Water, Carbon Dioxide, and Methane Determined by Displacement Technique Manoochehr Akhlaghinia, Farshid Torabi,* and Christine W. Chan Faculty of Engineering, University of Regina, Regina, Saskatchewan, Canada S4S 0A2 ABSTRACT: Two coreflood setups were used to measure heavy oil−water, heavy oil−carbon dioxide, and heavy oil−methane relative permeabilities. Using fractional effluents measured with precision meters and differential pressure data records, the Johnson−Bossler−Naumann technique was applied to calculate two-phase relative permeability in a consolidated sandstone core. In order to investigate the effect of temperature on the shape of relative permeability curves, a series of coreflood tests was conducted at three different temperatures (28, 40, and 52 °C) for each fluid pair. Analysis of the data obtained for the heavy oil− water system showed a linear increase of about 65% and 50% in water relative permeabilities when temperature ranged from 28 to 40 °C and 40 to 52 °C, respectively. However, although the oil relative permeability curve showed an increase of about 70% when temperature increased from 28 to 40 °C, it was dramatically decreased by about 30% when temperature was increased from 40 to 52 °C. In the case of heavy oil−gas a different effect was observed for methane and carbon dioxide. Although both methane and carbon dioxide relative permeabilities increased nonlinearly at higher temperatures, oil relative permeability in the presence of carbon dioxide decreased when temperature increased. In contrast, in the presence of methane, oil relative permeability experienced a reduction of 80% from 28 to 40 °C followed by a considerable increase of 15-fold from 40 to 52 °C.

1. INTRODUCTION Although an overview on the literature, Table 1, suggests that relative permeability is a function of temperature as well as saturation, there is still no unanimous agreement on how temperature may influence relative permeability curves. In spite of such controversy over the effect of temperature on the relative permeability curves, in a simulation of thermal heavy oil recovery processes, relative permeability data are routinely being used with no consideration of such an effect. For the first time, Geffen et al.1 suggested that care should be taken to not allow wettability change, e.g., at elevated temperatures, during relative permeability measurements. Later, waterflood tests performed in a consolidated core over a temperature range from 24 to 260 °C showed a dependency of residual oil saturation, final oil recovery, and relative permeability on temperature.2 Another study3 showed the effect of temperature on various rock/fluid properties such as wettability, residual oil saturation, irreducible water saturation, relative permeability, interfacial tension, and contact angle. Both water and oil relative permeabilities measured by the Johnson−Bossler−Naumann technique increased at elevated temperatures due to a decrease in capillary pressure. The temperature influence on oil/water relative permeability ratio at water saturations of more than 55% was reported by Davidson.4 In the case of the nitrogen/oil relative permeability ratio, it was found to be completely temperature dependent. Davidson suggested the use of a temperature-dependent relative permeability in reservoir studies. Later, to explain the contradiction on the effect of temperature on relative permeability data, Ehrlich5 proposed a geometrical model based on contact angle variation with temperature. This analytical model showed that the water to oil © 2013 American Chemical Society

relative permeability ratio increases in consolidated sands with low residual oil saturation. It also supports the results obtained by Habowski,6 where he found a decrease in the water to oil relative permeability ratio in consolidated sands at higher residual oil saturations. To increase the accuracy of the average saturation measurement, Lo and Mungan7 took advantage of an electrical resistivity technique to indirectly measure the saturation of the phases in the porous media. The effect of temperature was observed to be the same for both oil and water systems, as it increased both water and oil relative permeabilities. Lo and Mungan reported that the effect of temperature is more realistic for large oil/water viscosity ratio systems. The effect of temperature was also observed on the relative permeability data measured in artificial porous media such as Teflon (oil-wet), alumina (water-wet), and stainless steel (mixed-wet) by Lefebvre.8 Similar to Davidson, they strongly recommended that relative permeability data must be taken at reservoir temperatures to obtain more realistic results. A series of experiments conducted in sandstone cores by Weibrandt et al.9 indicated that an increase in temperature can affect the oil/water relative permeability ratio as well as the absolute permeability of the core. In addition to temperature effects, Sufi et al.10 found that the relative permeability, to a certain extent, depends on the flow rate used in the experiment. No sensible change was observed in the relative permeability data measured at temperatures ranging from 20 to 85 °C.10 Received: July 25, 2012 Revised: February 26, 2013 Published: February 26, 2013 1185

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Table 1. Summary of Studies Addressing the Effect of Temperature on Relative Permeability Data effect of increasing temperature on researcher

technique

porous media

kro

24−260

krw/kro less sloped

20−150

increase

24−282 24−104 24−150

Teflon−alumina− steel core sandpack core

2−130 @ 20 °C (multiple fluids) 0.56−60 @ 20 °C (multiple fluids) 65 @ 38 °C not reported 1−2 @ 22 °C

krw/kro less sloped krw/kro increases in sandpack, krw/kro decreases in core increase increase

26−157 20−85 22−175

dependency on viscous forces increase independent decrease

core

not reported

22−175

more water wetness

bitumen plugs not applicable

16 400 @ 24 °C 19.95 @ 38 °C

20−272 20−120

independent increase

decrease increase

unsteady state steady state steady state unsteady state

silica sand core sandpack core

1190 @ 21 °C 3 @ 24 °C 77 @ 52 °C 32.1 @ 38 °C

25−200 24−150 52−120 20−150

increase decrease independent viscosity and

unsteady state simulated annealing

core diatomite core

320 @ 20 °C 640 @ 44 °C

20−65 120−180

increase decrease independent dependency on wettability independent increase

unsteady state

core 550−580 md

Poston et al. (1970)

unsteady state

candpack

Davidson (1969) Ehrlich (1970)

unsteady state analytical

candpack 5.7 md core−sandpack

Lo and Mungan (1973)

steady state

Teflon−core

Lefebvre (1973)

unsteady state

Weinbrandt et al. (1975) Sufi et al. (1982) Torabzadeh and Handy (1984) Kumar et al. (1985)

steady state steady state steady state, unsteady state steady state, unsteady state unsteady state analytical

Akin et al. (1999) Schembre et al. (2006)

krw

40−600 @ 38 °C (multiple fluids) 80−600 @ 20 °C (multiple fluids) 65 @ 38 °C not reported

Edmondson (1965)

Maini and Batycky (1985) Nakornthap and Evans (1986) Maini and Okazawa (1987) Watson and Ertekin (1988) Polikar et al. (1990) Kumar and Inouye (1994)

temp. range, °C

viscosity (mPa·s)

24

increase

capillary to increase independent increase

independent increase

temperature as long as both viscosity and wettability are maintained. Their dynamic displacement experiments showed that the relative permeability was more dependent on the viscosity ratio rather than temperature. Using an innovative procedure to obtain reproducible sand packs with the same porosity and permeability, Polikar et al.16,17 repeated several steady state relative permeability measurements with a bitumen and water system. Statistical analysis of the results indicated no significant change in relative permeability and critical saturation. Nakornthap and Evans18 used data in the literature to mathematically demonstrate, in terms of water saturation and irreducible water saturation, dependency of relative permeability on temperature. Implementation of the model showed that water and oil relative permeability decrease and increase, respectively, with an increase in temperature. It was suggested that use of relative permeability data measured at room temperature in the thermal process may yield pessimistic results. The effect of the temperature gradient on the relative permeability curves was also investigated by Watson and Ertekin19 whereby fluids were injected at different temperatures into a sandstone core. In contradiction to earlier studies, both water and oil relative permeability decreased at higher temperature gradients. The effect of temperature on critical saturations was the same as that reported by previous researchers. Akin et al.20 believed that the contradiction among the experimental relative permeability data can be due to • inaccurate saturation measurement, • errors due to ignoring capillary pressure and end effects, • change in wettability by miscible cleaning,

The telative permeability measured by steady and unsteady state techniques by Torabzadeh and Handy11 in a consolidated silica−n-dodecane−water system shows a completely different dependency on temperature. Unlike other studies, the ndodecane relative permeability increased with temperature while the water relative permeability decreased at elevated temperatures up to 175 °C. Complex opposing effects of temperature and interfacial tension did not allow Kumar et al.12 to propose a single equation to predict the shape of the relative permeability curves at elevated temperatures. Experimental results indicated that the relative permeability curves sensibly show more water wetness at higher temperatures. The temperature influence on the end point relative permeability of heavy oil (16 400 mPa·s)−water systems measured by the history matching technique was reported by Maini and Batycky.13 While the oil end point relative permeability decreased with an increase in temperature, the water end point relative permeability remained unchanged. Irreducible water saturation was found to increase with an increase in temperature; however, residual oil saturation was found to decrease with an increase in temperature up to an optimum temperature and then the trend reversed. The displacement technique was applied for a silica−heavy oil−water system by Maini and Okazawa14 with attempts made to reduce artifacts with implementation of the technique. Although it was admitted that the unsteady state technique is prone to erroneous results, a meaningful increase in both heavy oil and water relative permeability data by an increase in temperature was observed. Kumar and Inouye15 proposed that a relative permeability curve measured at low temperature can be used at elevated 1186

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Figure 1. Schematic diagram of the experimental setup used for measurement of heavy oil−water relative permeability using the unsteady state technique.

Figure 2. Schematic diagram of the experimental setup used for measurement of heavy oil−gas relative permeability using unsteady state technique.

• erroneous derivative calculation. Relative permeability data estimated by the Simulated Annealing technique also exhibited observable temperature effects. Schembre et al.21 used this technique to estimate heavy oil−water relative permeabilities in low permeable cores. A reasonable shift toward more water wettability was observed with an increase in temperature. Table 1 chronicles most of studies that have addressed the effect of temperature on relative permeability data. As shown in column 3, the effect of temperature on relative permeability data has been mostly investigated for light to medium oil− water systems. It is believed that much more attention should be paid to systems including heavy oils since temperature effects on the heavy oils are very significant compared to lighter oils. The focus of this study is to determine the effect of temperature on different two-phase flow of heavy oil in the presence of water, methane, and carbon dioxide in consolidated sandstone. The JBN technique was applied to measure relative permeabilities from a series of coreflood tests conducted at three different temperatures, 28, 40, and 52 °C. The authors believe that the results of this work can be useful in more realistic simulation of processes such as hot waterflooding,

steam injection, gas injection, and carbon dioxide sequestration in depleted reservoirs.

2. EXPERIMENTAL SETUP AND PROCEDURE 2.1. Experimental Setup. Two experimental setups were used in this study for measuring two-phase relative permeabilities of heavy oil−water and heavy oil−gas (carbon dioxide and methane) with the unsteady state technique. Figures 1 and 2 present schematic diagrams of the setups for heavy oil−water and heavy oil−gas, respectively. All experiments were conducted with a high-pressure, 2.54 cm core holder (TEMCO-TCHR5000). The main elements are a Teledyne Isco syringe pump (500D series), core holder, transfer cylinder for injecting heavy oil, temperature controller, back pressure regulator with a nitrogen cylinder, and Validyne UPC2100 data acquisition system for an accurate record of pressure across the core holder. The Validyne UPC2100 data acquisition system allows receiving and recording signals from the pressure transducer. The temperature controlling system consists of a heat gun, temperature controller (Cole Parmer 89000-00) with a temperature probe, and two fans to maintain constant temperature up to 52 °C and homogeneous within the air bath. In the case of the heavy oil−gas setup, to have better control on gas injection, a precise gas flow controller (Bronkhorst F-230M-AAD11K) was used to inject gas at constant flow rates. The effluent passed through a separator by which oil samples were collected in test tubes and gas flow was directed to a gas flow meter (Cole Parmer 32907-71). 1187

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2.2. Fluid/Rock Properties. Two-phase relative permeability measurements were conducted for heavy oil−water and heavy oil− gas systems. In order to prevent any damage to the core, a 1 wt % NaCl in deionized water solution was used in all experiments. The viscosity of the original heavy oil was measured 4338 cP at 28 °C. It was filtered upon receiving, and the viscosity was altered through addition of kerosene as a diluant. The viscosity of the diluted oil with API gravity of 10.71 as a function of temperature is presented in Figure 3. Figure 4 presents brine viscosity versus temperature. A consolidated

test, porosity and permeability were measured to make sure that the miscible cleaning process did not alter the properties of the core. 2.4. General Testing Procedure. Clean, dried core was first weighed and then placed into the core holder. After applying 800 psi overburden pressure, carbon dioxide gas was injected at a high rate for 2 h to remove any remaining toluene in the core. Desired temperature was set on the temperature controller, and the two transfer cylinders were filled with heavy oil and brine and allowed to equilibrate for 24 h. The core was then vacuumed and saturated with brine to measure porosity and establish the initial condition of 100% brine saturation. Next, the core was flushed with 20 pore volumes of brine at 0.05 mL/ min to restore any wettability alteration that may have occurred by miscible cleaning. After this process absolute permeability was measured by brine injection at several different flow rates ranging from 0.1 to 5 mL/min. Assuring there was no change with the porosity and absolute permeability, oil was injected at a constant rate of 0.1 mL/min via a transfer cylinder. Back pressure was maintained by an Equilibar Precision back pressure regulator set at 150 psi. In all cases, including absolute and relative permeability measurement, overburden pressure was set at 800 psi. Oil injection was continued for 15 pore volumes to achieve irreducible water saturation. Injection was then stopped, and the core assembly was allowed 12 h to allow the pressure gradient along the core to settle out and reach equilibrium. In the next phase of the experiment, as for the heavy oil−water system, water was injected at a constant rate of 0.1 mL/min and continued for 15 pore volumes until residual oil saturation was achieved. In the case of carbon dioxide and methane, a precise gas flow controller was fed with a constant pressure of 700 Psia from a gas cylinder to precisely inject gas at constant rate of 11 mLn/min (normal milliliter per minute). Liquid effluent fractions were collected in the graduated centrifuged tubes at specific time steps and centrifuged for fractional and recovery analysis. Gas effluent was passed through a gas flow meter via a resinsealed separator to record gas flow rate out of the core holder.

Figure 3. Viscosity versus temperature for heavy oil used in the experiments.

3. RESULTS AND DISCUSSION The procedure described above was repeated three times for different temperatures of 28, 40, and 52 °C. With differential pressure and fractional effluent data, the JBN technique was applied to calculate heavy oil, water, carbon dioxide, and methane relative permeabilities. Average saturations were calculated using the material balance method. Attempts were made to have dead volumes in the system as low as possible to minimize errors with the material balance calculation. Previous studies showed that gas solubility depends mainly on pressure, temperature, oil viscosity, and time.22−24 Since the oil sample used in this study was heavy and experiments were conducted at a relatively low pressure (150 psi) and short time span, it was assumed that the solubility of carbon dioxide and methane (in heavy oil sample used in the study) at the temperature/pressure condition of experiments is negligible. Moreover, close monitoring of the produced samples did not indicate considerable gas bubbling out of the oil, and almost in all cases it was observed that two separate phases of fluids (gas and oil) were produced. Heavy oil viscosity was routinely measured to ensure that no alteration in heavy oil viscosity occurs due to probable vaporization of kerosene during the experiments. No viscosity change was observed even for the oil produced, indicating no considerable mass transfer occurred in the cases of gas injections. Capillary pressure was also ignored since it was speculated that it probably does not make any considerable difference in investigating the effect of temperature on relative permeabilities. Although, as expected, a high pressure drop was observed until breakthrough due to the presence of heavy oil in the core, a dramatic decrease in the pressure occurred after

Figure 4. Viscosity versus temperature for brine used in the experiments.

Table 2. Properties of the Core Used for Relative Permeability Measurementsa length (cm) diameter (cm) dry weight (kg) saturated weight (kg) pore volume (cm3) porosity (%) absolute permeability (Darcy) a

29.7 2.54 0.2925 0.3218 29.01 19.27 1.56

1 Darcy =10−12 m2.

sandstone core with dimensions presented in Table 2 was utilized as porous medium. Porosity measured by both weighting and gravity saturation gave a value of 21.67% pore volume. Absolute permeability was measured to be 1.56 Darcy by brine injection at different rates at a temperature of 28 °C. 2.3. Cleaning Procedure. The core was cleaned by flushing with 10 pore volumes of kerosene followed by 10 pore volumes of toluene at 0.05 mL/min. The core was hot air dried by exposing to a heating fan for 36 h at a moderate temperature of 60 °C. Before starting each 1188

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breakthrough. In cases of carbon dioxide and methane injections, low differential pressure (up to 5 psi) across the core after breakthrough allowed us to assume that both gas volume and rate do not considerably change in the core. In the case derivative calculations, the tangent line passing at each point was used as derivative since difficulties had been experienced in fitting data with conventional curve-fitting techniques, Figures 5 and 6. The detailed procedure of JBN techniques applied in this study is available in ref 25.

Figure 8. Heavy oil−water relative permeabilities at 40 °C.

Figure 5. Sample graph of produced fluid in PV versus injected fluid in PV, heavy oil/water system. Figure 9. Heavy oil−water relative permeabilities at 52 °C.

Figure 6. Sample graph of 1/Qi versus 1/(Qw × Ir), heavy oil/water system.

3.1. Heavy Oil−Water System. Figures 7−9 show the relative permeability curves at different temperatures taken by

Figure 10. Effect of temperature on the water relative permeability curves, heavy oil−water system.

Figure 7. Heavy oil−water relative permeabilities at 28 °C.

Figure 11. Effect of temperature on the heavy oil relative permeability curves, heavy oil−water system.

water injection into the sandstone core saturated with heavy oil at irreducible water saturation. The best trendlines passed through the data points, allowing for better demonstration of the relative permeability curves. Figures 10 and 11 show that temperature has different effects on water and oil relative permeability curves. In the case of water relative permeability, Figure 10, the curves shifted upward by about 65% when

temperature ranged from 28 to 40 °C. Almost the same increase was calculated for relative permeability curves at 40 and 52 °C. With the same difference between these curves it can be concluded that temperature linearly increases the water relative permeability curves. In the case of oil relative permeability curves, although an approximate 70% increase in 1189

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relative permeabilities can be estimated from 28 to 40 °C, the relative values decrease by about 30% when temperature ranged from 40 to 52 °C. It means that the oil relative permeability shifts up until an optimum temperature somewhere between 40 and 52 °C and then the trend reverses as temperature increases further. Compared to the studies by other researchers, the effect of temperature on water relative permeability is the same as the results observed by Poston et al.,3 Lo and Mungan,7 Weinbrandt et al.,9 Maini and Okazawa,14 Nakornthap and Evans,17 and Schembre et al.19 In terms of the effect of temperature on the krw/kro ratio, Figure 12 shows that Figure 14. Heavy oil−carbon dioxide relative permeabilities at 40 °C.

Figure 12. Effect of temperature on the krw/kro ratio in a heavy oil− water system.

Figure 15. Heavy oil−carbon dioxide relative permeabilities at 52 °C.

temperature tends to increase the ratio. This increase is more sensible from 40 to 52 °C compared to 28 to 40 °C. The effect of temperature on the krw/kro ratio observed in this study is the same as results expected by the analytical model proposed by Ehlrich5 for sandpacks. No shift in the slope of the krw/kro ratio, as reported by Edmondson2 and Davidson,4 can be seen in Figure 12. 3.2. Heavy Oil−Carbon Dioxide System. Two-phase relative permeability measurements for the heavy oil−carbon dioxide pair performed at three temperatures are presented in Figures 13−15. Figures 16 and 17 present the opposite effect of Figure 16. Effect of temperature on the gas relative permeability curves, heavy oil−carbon dioxide system.

Figure 13. Heavy oil−carbon dioxide relative permeabilities at 28 °C. Figure 17. Effect of temperature on the heavy oil relative permeability curves, heavy oil−carbon dioxide system.

temperature on carbon dioxide and heavy oil relative permeability curves, as it tends to increase the carbon dioxide relative permeability and, in contrast, reduce the relative permeability of the heavy oil. In the case of the effect of temperature on the krg/kro ratio, Figure 18 indicates temperature nonlinearly increases the ratio. This effect is more visible for the 40−52 °C interval than that of 28−40 °C. Compared to the Davidson4 study by which temperature reduced the slope of the nitrogen/No. 15 white oil relative permeability ratio, such a

change cannot be seen in Figure 18 since temperature only shifts the curves upward. 3.3. Heavy Oil−Methane System. Figures 19−21 present results of applying the displacement technique for the heavy oil−methane system. The effect of an increase in temperature on the methane relative permeability is the same as those for water and carbon dioxide as it increases methane relative 1190

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Figure 18. Effect of temperature on the krg/kro ratio in a heavy oil− carbon dioxide system.

Figure 22. Effect of temperature on the gas relative permeability curves, heavy oil−methane system.

Figure 19. Heavy oil−methane relative permeabilities at 28 °C.

Figure 23. Effect of temperature on the heavy oil relative permeability curves, heavy oil−methane system.

Figure 20. Heavy oil−methane relative permeabilities at 40 °C. Figure 24. Effect of temperature on the krg/kro ratio in a heavy oil− methane system.

ratio curves is the same those for water and carbon dioxide systems as an increase in temperature shifts the curve upward. A summary of the results observed in this study is presented in Table 3. Note that the term increase/decrease means that the corresponding parameter increases from 28 and 40 °C and then decreases from 40 and 52 °C. 3.4. Repeatability Tests. Three cases were randomly selected for repeatability tests, Table 4. Average error was Figure 21. Heavy oil−methane relative permeabilities at 52 °C.

Table 3. Summary of the Effect of Temperature on Relative Permeability Curves for Different Systems krw

permeability, Figure 22. Heavy oil relative permeability tends to decrease from 28 to 40 °C, and then as temperature further increases, it dramatically increases, Figure 23. This figure indicates a retrograde behavior of the heavy oil relative permeability by temperature. As it can be seen in Figure 24, in spite of some overlap of krg/kro ratio curves for 28 and 40 °C, it can be concluded that the effect of temperature on the krg/kro

heavy oil− water heavy oil− carbon dioxide heavy oil− methane 1191

krg

kro

krw/kro increase

increase

increase/ decrease decrease

increase

increase

decrease/ increase

krg/kro

increase increase

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Table 4. Summary of Maximum Error after Repeatability Tests fluid system water/heavy oil CO2/heavy oil CH4/heavy oil

temp. (°C)

no. of tests repeated

maximum least square error (%)

52

2

6

40 28

3 2

9 8

Article

AUTHOR INFORMATION

Corresponding Author

*Phone: +1-306-337-3287. Fax: +1-306-585-4855. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS We would like to thank the Petroleum Technology Research Centre (PTRC) for their funding support. Also, we extend our gratitude to Mr. Alireza Qazvini Firouz for his assistance during the experimental and simulation tests and Mr. Ryan Wilton for editing the manuscript.

calculated by the least-squares error method. As an example, in the case of the heavy oil/carbon dioxide system at 40 °C, the test was repeated three times and results are presented in Figure 25, indicating good agreement with each other. In total,

■ ■

NOMENCLATURE krw = water relative permeability, fraction kro = oil relative permeability, fraction krg = gas relative permeability, fraction Sw = water saturation, fraction So = oil saturation, fraction REFERENCES

(1) Geffen, T. M.; Owens, W. W.; Parrish, D. R. Experimental investigation of factors affecting laboratory relative permeability measurements. Pet. Trans. AIME 1951, 192, 99−110. (2) Edmondson, T. A. Effect of temperature on waterflooding. J. Can. Pet. Technol. 1965, 4 (4), 236−242. (3) Poston, S. W.; Israel, S.; Hossain, A. K. M. S.; Montgomery, E. F., III; Ramey, H. R., Jr. The effect of temperature on irreducible water saturation and relative permeability of unconsolidated sands. Soc. Pet. Eng. J. 1970, 10 (2), 171−180. (4) Davidson, L. B. The effect of temperature on the permeability ratio of different fluid pairs in two-phase systems. J. Pet. Technol. 1969, 246 (8), 1037−1046. (5) Ehlrich, R. The effect of temperature on water-oil imbibition relative permeability. Proceedings of the Society of Petroleum Engineers (SPE) Eastern Regional Meeting, Pittsburgh, PA, Nov 5−6, 1970; SPE Paper 3214-MS; Society of Petroleum Engineers: Richardson, TX, 1970. (6) Habowski, E. The effects of large temperature changes on relative permeability ratios. M.Sc. Thesis, The Pennsylvania State University, 1966. (7) Lo, H. Y.; Mungan, N. Effect of temperature on water-oil relative permeabilities in oil-wet and water-wet systems. Proceedings of the Fall Meeting of the Society of Petroleum Engineers (SPE) of AIME, Las Vegas, NV, Sept 30−Oct 3, 1973; SPE Paper 4505-MS; Society of Petroleum Engineers of AIME: Richardson, TX, 1973. (8) Lefebvre, E. J. Factors affecting liquid-liquid relative permeabilities of a consolidated porous medium. Soc. Pet. Eng. J. 1973, 13 (1), 39−40. (9) Weinbrandt, R. M.; Ramey, H. J., Jr.; Casse, F. J. The effect of temperature on relative and absolute permeability of sandstones. Soc. Pet. Eng. J. 1975, 15 (5), 376−384. (10) Sufi, A. H.; Ramey, H. J., Jr.; Brigham, W. E.; Temperature effects of relative permeabilities of oil-water systems. Proceedings of the Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition, New Orleans, LA, Sept 26−29, 1982; SPE Paper 11071MS; Society of Petroleum Engineers of AIME: Richardson, TX, 1982. (11) Torabzadeh, S. J.; Handy, L. L. The effect of temperature and interfacial tension on water/oil relative permeabilities of consolidated sands. Proceedings of the Society of Petroleum Engineers (SPE) Enhanced Oil Recovery Symposium, Tulsa, OK, April 15−18, 1984; SPE Paper 12689-MS; Society of Petroleum Engineers: Richardson, TX, 1984. (12) Kumar, S.; Torabzadeh, S. J.; Handy, L. L. Relative permeability functions for high- and low-tension systems at elevated temperatures. Proceedings of the Society of Petroleum Engineers (SPE) California

Figure 25. Repeatability tests in the case of heavy oil−carbon dioxide system at 40 °C.

21 tests were performed during the study which includes 9 tests presented here, 4 repeatability tests, and 8 technically failed tests.

4. CONCLUSIONS Using the unsteady state, JBN technique, relative permeability curves were measured for three systems of heavy oil−water, heavy oil−carbon dioxide, and heavy oil−methane at three different temperatures in consolidated sandstone. Each experiment involved water or gas injection into a core saturated with heavy oil at irreducible water saturation until residual oil saturation was achieved. Under the conditions pertaining to this study, the following conclusions can be made. • Relative permeability cannot be considered as a single function of saturation, since temperature was shown to have an effect on the relative permeability data. • Effect of temperature on two-phase relative permeability curves differs for different systems of heavy oil−water, heavy oil−carbon dioxide, and heavy oil−methane. • Relative permeability of water, carbon dioxide, and methane increases with increasing temperature in the presence of heavy oil. • Results of this study showed that heavy oil relative permeability decreases with temperature in the presence of water. Opposite retrograde behavior has been observed for heavy oil relative permeability in the presence of carbon dioxide and methane. • Relative permeability ratio increases regardless of fluids in a two-phase flow system. • Although wettability alteration has not been investigated here, the same as light oil systems studied in other studies, wettability alteration by temperature is expected to be the main mechanism for dependence of relative permeability curves on temperature. 1192

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dx.doi.org/10.1021/ef301248y | Energy Fuels 2013, 27, 1185−1193