Oil Recovery and Permeability Reduction of a Tight Sandstone

ARTICLE pubs.acs.org/IECR

Oil Recovery and Permeability Reduction of a Tight Sandstone Reservoir in Immiscible and Miscible CO2 Flooding Processes Xiaoqi Wang and Yongan Gu* Petroleum Technology Research Centre (PTRC), Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, Saskatchewan S4S 0A2, Canada ABSTRACT: In this paper, oil recovery and permeability reduction of a tight sandstone reservoir in immiscible and miscible CO2 flooding processes are experimentally studied. First, a series of saturation tests are conducted to determine the onset pressure of asphaltene precipitation from a light crude oil-CO2 system. Second, the vanishing interfacial tension (VIT) technique is applied to determine the minimum miscibility pressure (MMP) between the light crude oil and CO2. Third, a total of nine CO2 coreflood tests under immiscible and miscible conditions are performed through the so-called dry, secondary, and tertiary oil recovery processes, respectively. It is found that the onset pressure of asphaltene precipitation is much lower than the MMP. In the CO2 secondary oil recovery process, the coreflood test data show that, when the injection pressure is between the onset pressure of asphaltene precipitation and the MMP, the oil recovery factor is higher but the oil effective permeability reduction is larger at a higher injection pressure in the immiscible CO2 flooding. They both reach almost constant maximum values in the miscible CO2 flooding (P g MMP). It is also found that, in three different miscible CO2 oil recovery processes, the CO2 tertiary flooding process gives the lowest oil recovery factor but the largest oil effective permeability reduction. This is attributed to the most severe codeposition of asphaltenes and metal carbonates. However, the CO2 dry or secondary flooding process has a significantly higher oil recovery factor but a much smaller oil effective permeability reduction due to asphaltene deposition alone in the former process or codeposition of asphaltenes and metal carbonates in the latter process.

1. INTRODUCTION Carbon dioxide tertiary or even secondary oil recovery becomes increasingly important to the petroleum industry. After the secondary water flooding, many light and medium oil reservoirs are suitable for miscible or even immiscible CO2 flooding. This is because CO2 flooding can not only effectively enhance or improve oil recovery but also considerably reduce greenhouse gas emissions.1 Over the past six decades, there have been extensive laboratory studies, numerical simulations, and field applications of CO2 flooding in different oil recovery processes for various light and medium oil reservoirs. It has been found from a laboratory study that the ultimate oil recovery factor of a CO2 secondary flood is over 60% of the original-oil-in-place (OOIP), which is significantly higher than 44% of the OOIP, an average oil recovery factor of a secondary water flood.2 After CO2 is injected into an oil reservoir, it contacts the reservoir oil and, thus, changes the equilibrium conditions and fluid properties, which may lead to the precipitation of organic solids, primarily asphaltenes.3 In addition, the injected CO2 can also dissolve into the reservoir brine. The carbonated brine reacts with some cations (e.g., calcium and magnesium ions) to cause the precipitation and deposition of insoluble metal carbonates (e.g., CaCO3 and MgCO3) onto the reservoir rocks. Thus, some small pores of the reservoir formation may be plugged, and its permeability may be reduced due to codeposition of asphaltenes and metal carbonates.4 It is also found that the carbonated brine can react with carbonate minerals in the carbonate reservoir to cause the dissolution of the main rock matrix and formation of new flow paths and, thus, increase the formation permeability.5 Therefore, CO2 flooding and its oil recovery process through a r 2011 American Chemical Society

tight light or medium oil reservoir are complex and need to be studied in detail. Asphaltenes are the heaviest and most complicated fraction in a crude oil sample and consist of condensed polynuclear aromatics, small amounts of heteroatoms (S, N, and O), and some traces of metal elements. They are generally characterized as insoluble materials in a low boiling-point alkane, e.g., n-pentane or n-heptane.6 Also, during the solvent-based oil recovery processes, e.g., vapor extraction (VAPEX) and CO2 flooding, asphaltenes will precipitate and then deposit onto the reservoir rocks if the solvent concentration in the crude oil is high enough.7,8 In this case, the deposited asphaltenes may cause reservoir plugging and wettability alteration and significantly reduce the oil recovery. If the precipitated asphaltenes are produced from the reservoir formation, they can severely plug wellbore and cause downstream surface separation and treatment problems.9 In addition, even though the asphaltene content in some light crude oil is extremely low, the operating problem caused by asphaltene precipitation can still be serious under certain circumstances.10 For example, production of Hass-Messaoud crude oil in Algeria with only 0.15 wt % asphaltenes causes numerous problems attributed to their precipitation and deposition onto the reservoir formation, downhole wellbore, and surface facilities.11 This is due to small pore throats of the tight light oil reservoir and significant reduction of resin-to-asphaltene ratio in the light crude oil as a Received: July 27, 2010 Accepted: December 16, 2010 Revised: October 29, 2010 Published: January 18, 2011 2388

dx.doi.org/10.1021/ie1016046 | Ind. Eng. Chem. Res. 2011, 50, 2388–2399

Industrial & Engineering Chemistry Research

ARTICLE

Table 1. Compositional Analysis Result for the Original Light Crude Oil with the Asphaltene Content of wasp = 0.260 wt % (n-Pentane Insoluble) carbon number wt % carbon number wt % carbon number

Table 2. Physical and Chemical Properties of the Cleaned Reservoir Brine at P = 1 atm

wt %

C1

0.00

C18

3.50

C35

1.18

C2

0.00

C19

2.40

C36

1.06

C3

0.04

C20

2.60

C37

0.69

C4

0.31

C21

2.58

C38

0.59

C5 C6

1.19 1.92

C22 C23

1.58 2.24

C39 C40

0.90 0.70

C7

4.76

C24

1.93

C41

0.69

C8

3.66

C25

2.00

C42

0.59

C9

4.34

C26

1.87

C43

0.58

C10

4.40

C27

1.82

C44

0.56

C11

4.00

C28

1.65

C45

0.56

C12

3.38

C29

1.62

C46

0.42

C13 C14

3.77 3.50

C30 C31

1.20 1.33

C47 C48

0.42 0.39

C15

3.53

C32

1.19

C49

0.39

C16

3.00

C33

0.94

C50þ

13.91

C17

3.30

C34

0.82

total

100.00

result of substantial CO2 dissolution.12 Therefore, it is important to determine the onset pressure of asphaltene precipitation for a given light crude oil-CO2 system and quantify the actual amount of deposited asphaltenes and corresponding permeability reduction after a CO2 flooding process is applied for a tight light oil reservoir. In this paper, a visual method is applied to determine the onset pressure of asphaltene precipitation for a light crude oil-CO2 system in a high-pressure saturation cell. Then, the equilibrium interfacial tensions (IFTs) between the light crude oil and CO2 are measured at different equilibrium pressures and T = 27 °C, and the so-called minimum miscibility pressure (MMP) is determined by applying the vanishing interfacial tension (VIT) technique. Lastly, a total of nine CO2 coreflood tests are undertaken using several sandstone reservoir core plugs in series under immiscible and miscible conditions to measure the oil recovery factor and oil effective permeability reduction. In particular, three different production processes, i.e., CO2 dry, secondary, and tertiary oil recovery processes, are conducted and compared to study the oil effective permeability reduction caused by asphaltene deposition alone in a CO2 dry oil recovery process or by codeposition of asphaltenes and metal carbonates in a CO2 secondary or tertiary oil recovery process.

2. EXPERIMENTAL SECTION 2.1. Materials. The original light crude oil sample was collected from Pembina Cardium oilfield in Alberta, Canada. The density and viscosity of the cleaned light crude oil sample were measured to be Foil = 835.0 kg/m3 and μoil = 5.5 mPa 3 s at the atmospheric pressure and T = 27 °C, respectively. The asphaltene content of the original light crude oil was measured to be wasp = 0.260 wt % (n-pentane insoluble) using the standard ASTM D2007-03 method13 and filter papers (Whatman No. 2, England) with a pore size of 2 μm. The compositional analysis result of this light crude oil was obtained using the standard ASTM D8614 and is given in Table 1. A reservoir brine sample was collected from the same oilfield, cleaned, and analyzed. Its

temperature (°C)

15

20

40

density (kg/m3)

1003.3

1002.2

996.2

viscosity (mPa 3 s) pH at 20 °C

1.17

1.02

0.66

7.94

specific conductivity (μS/cm) refractive index at 25 °C

7250 1.3335

chloride (mg/L)

1390

sulfate (mg/L) total dissolved solids

4.1 4660 (180 °C)

(mg/L) potassium (mg/L) sodium (mg/L)

15 1730

calcium (mg/L)

55

magnesium (mg/L)

15

iron (mg/L)

0.015

manganese (mg/L) barium (mg/L)

0.024 9.1

detailed physical and chemical properties are listed in Table 2. A number of sandstone reservoir core plugs were collected from several wells located in Pembina Cardium oilfield at the reservoir depth of approximately 1615 m. The purity of carbon dioxide (Praxair, Canada) used in this study is equal to 99.998 mol %. The densities of CO2 at different pressures and T = 27 °C were calculated using the CMG Winprop module (Version 2008.10, Computer Modelling Group Limited, Canada) with PengRobinson equation of state.15 2.2. Asphaltene Content Measurement. The asphaltenes were precipitated from the original or produced light crude oil sample using the standard ASTM D2007-03 method.13 More specifically, one volume of the oil sample was mixed with 40 volumes of liquid n-pentane, which was used as a precipitant. The oil-precipitant mixture was agitated using a magnetic stirrer (SP46925, Barnstead/Thermolyne Corporation, USA) for 12 h. Two pieces of 2 μm pore size filter papers were weighed using an electric balance (AG204, Mettler Toledo, Switzerland) before they were used to filter the oil-precipitant mixture. The filter cake, which was primarily composed of precipitated asphaltenes, was rinsed with n-pentane until the precipitant after passing through the filter papers remained colorless. The precipitated asphaltenes with the filter papers were slowly dried at T = 100 °C in an oven (650-58, Fisher Scientific, Canada) until their total weight did not change from the reading of the electric balance. With the measured weight change of the filter papers before and after filtration, the asphaltene content of the oil sample was determined accordingly. 2.3. Onset of Asphaltene Precipitation. In the literature, several methods have been developed to determine the onset pressure of asphaltene precipitation, which include the measurement of electrical conductivity, oil viscosity,16 interfacial tension,17 gravimetric analysis, light transmission, and the visual method. In this study, a visual method is applied to measure the onset pressure of asphaltene precipitation. Figure 1 shows the schematic diagram of the experimental setup used to determine the onset pressure of asphaltene precipitation from the original light crude oil-CO2 system. The major component of this experimental setup was a specially designed see-through windowed highpressure saturation cell with a total volume of 310 cm3. In this 2389

dx.doi.org/10.1021/ie1016046 |Ind. Eng. Chem. Res. 2011, 50, 2388–2399


ARTICLE

Figure 1. Schematic diagram of the experimental setup used for determining the onset pressure of asphaltene precipitation from the original light crude oil-CO2 system.

saturation cell, a thick stainless steel plate was machined and placed between two transparent acrylic plates or windows to form a rectangular cavity (30.48 5.08 1.91 cm3). The maximum operating pressure of this saturation cell is equal to 7.0 MPa at T = 21 °C. A light source and a glass diffuser (240-341, DynaLume, USA) were placed beneath the saturation cell to provide sufficient and uniform illumination for the CO2-saturated oil layer. A microscope camera (MZ6, Leica, Germany) was positioned above the saturation cell to capture the digital image of the CO2-saturated oil layer inside the saturation cell. The digital images of the CO2-saturated oil layer under different equilibrium pressures were acquired in tagged image file format (TIFF) using a digital frame grabber (Ultra II, Coreco Imaging, Canada) and stored in a DELL desktop computer. Prior to each saturation test, the saturation cell was cleaned with kerosene, then flushed with nitrogen, and finally vacuumed. The high-pressure saturation cell was pressurized with CO2 to P = 3.0 MPa at the beginning. Then, 5 cm3 of the original light crude oil was introduced into the saturation cell using a programmable syringe pump (100DX, ISCO Inc., USA). This small amount of the crude oil was chosen and injected into the saturation cell so that a thin oil layer (≈0.032 cm) was formed on the lower acrylic window of the saturation cell and, thus, could be sufficiently illuminated using the light source. The CO2-saturated oil layer was observed through the acrylic windows of the saturation cell using the microscope camera. The personal computer was connected to the microscope camera and used to acquire the digital image of the CO2-saturated oil layer at any time. In this way, any asphaltene deposits on the lower acrylic window at a high saturation pressure could be clearly observed. In particular, the corresponding onset pressure of asphaltene precipitation from the CO2-saturated oil layer was noted. 2.4. IFT Measurement. Figure 2 shows the schematic diagram of the experimental setup used for measuring the equilibrium IFT between the light crude oil and CO2 by applying the axisymmetric drop shape analysis (ADSA) technique for the

pendant drop case.18 The major component of this experimental setup was a see-through windowed high-pressure cell (IFT-10, Temco, USA). A stainless steel syringe needle was installed at the top of the pressure cell and used to form a pendant oil drop. The light crude oil was introduced from the original light crude oil sample cylinder (500-10-P-316-2, DBR, Canada) to the syringe needle using the programmable syringe pump. The light source and the glass diffuser were used to provide uniform illumination for the pendant oil drop. The microscope camera was used to capture the sequential digital images of the dynamic pendant oil drop inside the pressure cell at different times. The high-pressure cell was positioned horizontally between the light source and the microscope camera. The entire ADSA system and high-pressure cell were placed on a vibration-free table (RS4000, Newport, USA). The digital image of the dynamic pendant oil drop at any time was acquired in a TIFF file using the digital frame grabber and stored in the DELL desktop computer. The pressure cell was first filled with CO2 at a prespecified pressure and a constant temperature. After the pressure and temperature inside the pressure cell reached their stable values, the light crude oil was introduced from the original light crude oil sample cylinder to the high-pressure cell to form a pendant oil drop at the tip of the syringe needle. Once a well-shaped pendant oil drop was formed, the sequential digital images of the dynamic pendant oil drop at different times were acquired and stored automatically in the personal computer. Then, the ADSA program for the pendant drop case was executed to determine the dynamic IFT of the dynamic pendant oil drop. The IFT measurement was repeated for at least three different pendant oil drops to ensure satisfactory repeatability at each prespecified pressure and constant temperature. In this study, the crude oil-CO2 dynamic and equilibrium IFTs were measured at a constant temperature of T = 27 °C and 12 different equilibrium pressures in the range of P = 2.4-11.0 MPa. Only the average value of the equilibrium IFTs of three repeated IFT measurements at each equilibrium pressure will be presented. Then, the vanishing interfacial 2390



ARTICLE

Figure 2. Schematic diagram of the experimental setup used for measuring the equilibrium interfacial tension (IFT) between the light crude oil and CO2 by applying the axisymmetric drop shape analysis (ADSA) technique for the pendant drop case.

tension (VIT) technique was applied to determine the MMP of the light crude oil-CO2 system from the measured equilibrium IFT versus equilibrium pressure data. The VIT technique is based on the concept that the IFT between the oil and gas phases must approach zero when these two phases become miscible. 2.5. Coreflood Test. A schematic diagram of the coreflood apparatus used in CO2 coreflood tests is shown in Figure 3. Prior to each test, the sandstone reservoir core plugs were cleaned by applying Dean-Stark extractor (09-556D, Fisher Scientific, Canada). An automatic displacement pump (PMP-1000-1-10MB, DBR, Canada) was used to displace the crude oil, reservoir brine or CO2 through the composite reservoir core plugs inside a coreholder (RCHR-2.0, Temco, USA). The distilled water was pumped using a manual displacement pump (HAT-250-100, Temco, USA) to apply the so-called overburden pressure, which was always kept 5 MPa higher than the inlet pressure of the coreholder. The composite reservoir core plugs used in the nine CO2 coreflood tests were 16.3-22.2 cm long and 5.1 cm in diameter. Four high-pressure cylinders (500-10-P-316-2, DBR, Canada) were used to store and deliver the crude oil, reservoir brine, CO2, and distilled water, respectively. These four sample cylinders and the coreholder were placed inside an air bath. An electric heater (HZ-315C, Super Electric Co., Canada) and a temperature controller (Standard-89000-00, Cole-Parmer, Canada) were used to heat the air bath and keep its constant temperature of T = 27 °C. A back-pressure regulator (BPR; BPR50, Temco, USA) was used to maintain the prespecified injection pressure inside the coreholder during each CO2 flooding test. During the reservoir brine, original light crude oil, and CO2 injection processes, the differential pressure between the inlet and outlet of the coreholder was measured using a differential pressure transducer (P55D, Validyne, USA). The accumulative amount of CO2 from the produced oil and during the CO2 breakthrough process was measured using a gas flow meter

(GFM 17, Aalborg, USA). The differential pressure data and accumulative amounts of produced oil and CO2 were measured, recorded, and stored automatically in a computer at a preset time interval. The general procedure for preparing each CO2 coreflood test is briefly described as follows. The sandstone reservoir core plugs were placed in series inside a Dean-Stark extractor and cleaned with toluene, methanol, and chloroform in sequence to remove hydrocarbons, salts, and clays, respectively. After the sandstone reservoir core plugs were cleaned and dried, they were assembled in series in the horizontal coreholder and vacuumed for 48 h. Then, the cleaned reservoir brine was imbibed to measure the porosity of the composite reservoir core plugs. Afterward, the cleaned reservoir brine was injected at different flow rates (0.1-0.5 cc/min) to measure the absolute permeability of the composite core plugs. As listed in Table 3, the measured porosity was in the range of φ = 10.8-15.6% and the measured absolute permeability was in the range of k = 1.2-4.0 mD. For a CO2 dry oil recovery process (Test #8), which is CO2 secondary flooding in the absence of the connate water, the brine-saturated core plugs were removed from the coreholder and placed inside an oven (650-58, Fisher Scientific, Canada) at T = 120 °C for 48 h to vaporize any trapped brine after the absolute permeability measurement. Then, the core plugs were reassembled in series in the coreholder and saturated with the original light crude oil. After the core plugs were fully saturated with the crude oil, a total of 3.0 pore volume (P.V.) of the original light crude oil was further injected to pressurize the composite core plugs and ensure that the prespecified injection pressure was reached and that the differential pressure (ΔP1) between the inlet and outlet of the coreholder became stable. Then, CO2 was injected at a constant volume injection rate of qco2= 0.4 cc/min (i.e., 0.93 ft/D), P = 12.0 MPa, and T = 27 °C to recover the light crude oil from the composite core plugs. CO2 injection was 2391



ARTICLE

Figure 3. Schematic diagram of the high-pressure CO2 coreflood apparatus.

Table 3. Physical Properties of Composite Carbonate Reservoir Core Plugs, Experimental Conditions, Oil Recovery Factors and Oil Effective Permeability Reduction Data for Nine Coreflood Tests at T = 27 °Ca test no.

φ (%)

k (mD)

Soi (%)

Swc (%)

P (MPa)

CO2 RF (%)

total RF (%)

wasp (wt %)

ΔP1 (kPa)

ΔP2 (kPa)

Δko/ko (%)

1

15.6

4.0

56.5

43.5

2

14.7

2.5

56.3

43.7

4.8

43.2

43.2

0.160

130.0

140.0

8.57

5.4

43.9

43.9

0.154

652.0

717.1

3 4

12.4 10.8

1.4 2.5

63.3 63.3

36.7 36.7

9.07

6.3 7.4

59.7 80.9

59.7 80.9

0.149 0.141

476.0 239.2

524.0 267.5

9.17 10.59

5

14.4

3.5

60.5

6

11.5

2.6

62.1

39.5

8.2

81.7

81.7

0.139

1108.7

1253.0

11.94

37.9

12.0

80.8

80.8

0.137

1233.0

1396.0

7

15.6

2.2

11.67

59.2

40.8

14.0

79.1

79.1

0.138

4706.0

5294.4

8

12.8

11.17

1.2

99.0

0.0

12.0

74.5

74.5

0.124

331.0

365.4

9

15.2

9.43

2.0

62.9

37.1

12.0

25.4

61.2

0.447

6649.3

8501.3

21.78

water RF (%)

35.8

a Notes: φ: porosity; k: absolute permeability; Soi: initial oil saturation; Swc: initial connate water saturation; P: CO2/water injection pressure; RF: oil recovery factor at 1.5 P.V. of injected brine or 2.0 P.V. of injected CO2; wasp: asphaltene content of CO2-produced oil; ΔP1: stable differential pressure between the inlet and outlet of the coreholder during the initial original light crude oil injection before CO2 flooding; ΔP2: stable differential pressure between the inlet and outlet of the coreholder during the final original light crude oil reinjection after CO2 flooding; Δko/ko: oil effective permeability reduction in percentage after CO2 flooding.

terminated after a total of 2.0 P.V. was injected and no more oil was produced. After the produced oil passed through the BPR and flowed to a graduated sample collector, a digital video camera was used to record the volume of the produced oil and determine the accumulative oil production. Meanwhile, the flashed and

produced CO2 passed through the gas flow meter and its production rate and accumulative amount were measured. In a CO2 secondary oil recovery process (Tests #1-7), which is CO2 secondary flooding at the initial connate water saturation, the original light crude oil was injected through the brine-saturated 2392



ARTICLE

Figure 4. Digital images of asphaltene deposits on the lower acrylic window of the high-pressure saturation cell at 40 magnification and T = 27 °C.

core plugs until the initial connate water saturation was achieved. The initial connate water saturation was found to be Swc = 36.743.7%, and the original light crude oil saturation was in the range of Soi =56.3-63.3%. Then, a total of 3.0 P.V. of the original light crude oil was injected to pressurize the composite core plugs and ensure that the prespecified injection pressure was reached and that the differential pressure (ΔP1) between the inlet and outlet of the coreholder became stable. Afterward, CO2 was injected at the injection rate of qco2= 0.4 cc/min, at each prespecified injection process, and T = 27 °C. CO2 injection was terminated after a total of 2.0 P.V. was injected and no more oil was produced. The digital video camera was used to record the accumulative volume of the produced oil. The produced oil sample was first visually examined and then centrifuged to separate the oil and possible water phases. No connate water was produced and found in the visual examination and centrifuging process of the produced oil sample in any CO2 secondary oil recovery test. The accumulative volume of flashed and produced CO2 was measured and recorded using the gas flow meter. For a CO2 tertiary oil recovery process (Test #9), the preparation procedures for achieving the initial connate water saturation and injecting the subsequent 3.0 P.V. of the original light crude oil are the same as those described for a CO2 secondary oil recovery process. The initial connate water saturation for this test was Swc = 37.1% and the original light crude oil saturation was Soi = 62.9%. Then, the water flooding was conducted to recover the crude oil from the composite core plugs at the injection rate of qwater= 0.4 cc/min and stopped after a total of 1.5 P.V. of the reservoir brine was injected. The subsequent CO2 flooding was commenced for the tertiary oil recovery at the injection rate of qco2= 0.4 cc/min, P = 12.0 MPa, and T = 27 °C and terminated after a total of 2.0 P.V. was injected and no more oil was produced. The digital video camera was used to record the respective accumulative production data (i.e., volumes) of produced oil and brine. The accumulative volume of flashed and produced CO2 was measured and recorded using the gas flow meter during CO2 tertiary oil recovery process.

After each CO2 flooding test was terminated, a total of 3.0 P.V. of the original light crude oil was reinjected through the coreholder until the differential pressure (ΔP2) between its inlet and outlet became stable. With the two measured stable differential pressures during the initial original light crude oil injection (ΔP1) and the final original light crude oil reinjection (ΔP2), the oil effective permeabilities before and after CO2 flooding were determined by applying Darcy’s law, respectively. It is worthwhile to mention that the final water saturation after the original light crude oil reinjection in Test #9 reached Sw = 38.3%, which was slightly higher but very close to the initial connate water saturation of Swc = 37.1% for this test. Finally, a four-stage blow-down process was started and continued until the pressure inside the coreholder reached the atmospheric pressure and no more oil was produced.

3. RESULTS AND DISCUSSION 3.1. Onset Pressure of Asphaltene Precipitation. The saturation pressure inside the saturation cell was increased from 3.0 by 0.2 MPa in each step until the test pressure reached P = 4.4 MPa. It was found during the saturation test that the lower visual acrylic window was clean and transparent at P < 4.4 MPa, as shown in Figure 4a. This indicates that there were no observable asphaltene deposits. However, Figure 4b shows that the digital image suddenly became dark at P = 4.4 MPa, though the same light intensity was used. After this pressure, the saturation pressure was increased by 0.1 MPa in each step. At P = 4.8 MPa, some precipitated asphaltene particles were observed in the CO2saturated oil layer. Figure 4c shows a small surface area of the acrylic window with some asphaltene deposits at this pressure. As the saturation pressure was further increased, the observed asphaltene particles became larger and darker. In this case, more asphaltene particles were precipitated, as shown in Figure 4d for P = 5.2 MPa. At P = 5.6 MPa, the deposited asphaltene particles formed some large pieces of deposits in the CO2-saturated oil layer, as seen in Figure 4e. At P > 5.6 MPa, the morphology of the 2393



ARTICLE

Figure 5. Measured equilibrium interfacial tensions of the light crude oil-CO2 system at different equilibrium pressures and T = 27 °C.

observed asphaltene deposits remained essentially unchanged with the saturation pressure.8 It is concluded that the onset pressure of the asphaltene precipitation from the CO2-saturated oil layer tested in this study is 4.8 MPa at T = 27 °C. After the onset pressure of the asphaltene precipitation was determined, the saturation pressure was suddenly reduced to 3.0 MPa in order to ascertain the reversibility or redissolution of the asphaltene precipitation at a lower pressure. Figure 4f shows that almost all the precipitated asphaltenes were redissolved into the crude oil phase at P = 3.0 MPa. This means that the asphaltene precipitation is nearly reversible when the saturation pressure is suddenly and significantly reduced.19 3.2. Equilibrium IFT and MMP. In this study, the measured equilibrium IFTs between the crude oil and CO2 at different equilibrium pressures of P = 2.4-11.0 MPa and a constant temperature of T = 27 °C are plotted in Figure 5. It is found that the measured equilibrium IFT is reduced almost linearly with the equilibrium pressure in three distinct pressure ranges. In Range I (P = 2.4-5.5 MPa), the equilibrium IFT reduction is solely attributed to the increased solubility or dissolution of CO2 in the original light crude oil at an increased equilibrium pressure.20 In Range II (P = 6.2-7.2 MPa), the equilibrium IFT was suddenly increased to a higher value at P = 6.2 MPa and then reduced quickly and linearly again as the equilibrium pressure was increased to P = 7.2 MPa. This is due to the light-components extraction from the original light crude oil to CO2 phase and CO2 gas-to-liquid phase change.8,21 The onset pressure of the initial strong light-components extraction for the Pembina Cardium light crude oil-CO2 system tested in this study was found to be Pext = 6.4 MPa.22 The vapor pressure of CO2 is equal to Pv = 6.74 MPa at T = 27 °C.15 Thus, the pendant oil drop formed at the tip of the syringe needle was mainly composed of relatively heavy components of the original light crude oil. This lightcomponents extraction could be observed at the beginning of each IFT test at P g 6.4 MPa. As a result, the measured equilibrium IFT is between the relatively heavy components of the original light crude oil and CO2. In Range III (P = 7.2-11.0 MPa), an even stronger light-components extraction was observed. The crude oil had to be continuously introduced from the original light crude oil sample cylinder so that a well-shaped pendant oil drop could be formed at the tip of the syringe needle eventually for the IFT measurement. It should be noted that, in the third

Figure 6. (a) Differential pressure between the inlet and outlet of the coreholder in Test #8 versus the injected P.V. of the crude oil or CO2 during the initial original light crude oil injection before CO2 flooding, CO2 dry flooding, and final original light crude oil reinjection after CO2 flooding at qoil= 0.1 cc/min, qco2= 0.4 cc/min, and T = 27 °C. (b) Differential pressure between the inlet and outlet of the coreholder in Test #6 versus the injected P.V. of the crude oil or CO2 during the initial original light crude oil injection before CO2 flooding, CO2 secondary flooding, and final original light crude oil reinjection after CO2 flooding at qoil= 0.1 cc/min, qco2= 0.4 cc/min, and T = 27 °C. (c) Differential pressure between the inlet and outlet of the coreholder in Test #9 versus the injected P.V. of the crude oil or CO2 during the initial original light crude oil injection before CO2 flooding, secondary water flooding, CO2 tertiary flooding, and final original light crude oil reinjection after CO2 flooding at qoil= 0.1 cc/min, qwater= 0.4 cc/min, qco2= 0.4 cc/min, and T = 27 °C.

pressure range, the measured equilibrium IFT is between even heavier components of the original light crude oil and CO2. The equilibrium IFT was reduced slightly, and finally, it reached its lowest value of γeq= 1.15 mJ/m2 at the equilibrium pressure of 2394



ARTICLE

P = 11.0 MPa. The above experimental data and observations indicate that different groups of light components are extracted from the original light crude oil to CO2 phase and that the measured equilibrium IFT is between different heavy components of the original light crude oil and CO2 in the last two equilibrium pressure ranges (i.e., Ranges II and III). On the basis of the measured data (symbols) in Figure 5, the equilibrium IFT γeq (mJ/m2) is correlated to the equilibrium pressure P (MPa) by applying the linear regression in the abovementioned three equilibrium pressure ranges, respectively: γeq ¼ - 3:47P þ 26:03

ð2:4 MPaePe5:5 MPa,

R2 ¼ 0:988Þ

ð1Þ γeq ¼ - 9:06P þ 68:84


R2 ¼ 0:987Þ

ð2Þ γeq ¼ - 0:59P þ 7:68


R2 ¼ 0:988Þ

ð3Þ It is worthwhile to note that, for this light crude oil-CO2 system, the linear regression equations of the measured equilibrium IFT versus equilibrium pressure data for Ranges I and II converge to an almost same equilibrium pressure (i.e., the MMP) at γeq= 0. The MMP of the light crude oil-CO2 system is determined to be 7.5-7.6 MPa by applying the VIT technique.23,24 3.3. Oil Effective Permeability Reduction. In this study, the respective oil effective permeabilities were calculated from the measured differential pressures between the inlet and outlet of the coreholder during the initial original light crude oil injection before CO2 flooding and during its final reinjection after CO2 flooding at the injection rate of qoil = 0.1 cc/min and a constant temperature of T = 27 °C. A total of 3.0 P.V. of the original light crude oil was injected during the initial injection or final reinjection process so as to reach a stable differential pressure. Tests #8, #6, and #9 are chosen as examples to show the differential pressure versus injected P.V. data during the initial original light crude oil injection, water flooding and/or CO2 flooding, and final original light crude oil reinjection for CO2 dry, secondary, and tertiary oil recovery processes in Figure 6a-c, respectively. It can be seen from these three panels that the measured differential pressures before and after CO2 flooding could reach their stable values during the initial original light crude oil injection (ΔP1) and the final original light crude oil reinjection (ΔP2), which are listed in Table 3. The differential pressure measured during the final original light crude oil reinjection after CO2 flooding is always higher than that measured during its initial injection before CO2 flooding, i.e., ΔP2 > ΔP1. A similar trend is also found for the measured differential pressures in the other six tests. The measured stable differential pressures before and after CO2 flooding were used to calculate the oil effective permeabilities using Darcy’s law, respectively. The calculated oil effective permeability reduction in percentage for each test is given in Table 3. Detailed analyses and comparison of these oil effective permeability reduction data for different CO2 oil recovery processes are presented in the subsequent two sections. 3.4. CO2 Secondary Oil Recovery. In this study, a total of seven CO2 coreflood tests for CO2 secondary oil recovery were carried out at different injection pressures and T = 27 °C. A constant CO2 volume injection rate of qco2= 0.4 cc/min was used to

Figure 7. (a) Measured oil recovery factor of CO2 secondary flooding versus the injected P.V. of CO2 at qco2= 0.4 cc/min and T = 27 °C. (b) Measured accumulative producing GOR of CO2 secondary flooding versus the injected P.V. of CO2 at qco2= 0.4 cc/min and T = 27 °C. (c) Measured asphaltene content of CO2-produced oil, oil recovery factor, and oil effective permeability reduction in CO2 secondary flooding at 2.0 P.V. of injected CO2, qco2= 0.4 cc/min, and T = 27 °C.

examine the effect of injection pressure on the secondary oil recovery process. The detailed physical properties of the composite core plugs for CO2 secondary oil recovery tests (Tests #1-7) are summarized in Table 3. Since the onset pressure of asphaltene precipitation was determined to be Ponset = 4.8 MPa, the injection pressure of the CO2 coreflood tests was chosen in the range of 4.8 MPa e P e 14.0 MPa. Moreover, it is worthwhile to mention that, after the initial connate water saturation was reached through the initial original light crude oil injection, no more water was produced during the CO2 secondary oil recovery 2395


Industrial & Engineering Chemistry Research and final original light crude oil reinjection. The oil recovery factor (RF) at any P.V. of the injected fluid under the coreflood test conditions is defined as the ratio of the volume of the produced oil at any time to that of the initial original light crude oil in the composite core plugs. Figure 7a shows the measured oil RF versus the injected P.V. of CO2 at seven different injection pressures. As expected, oil RF is increased with the injected P.V. of CO2. The oil recovery at each injection pressure reaches its maximum value after at most 1.5 P.V. of CO2 is injected. In this study, each CO2 coreflood test was terminated at 2.0 P.V. of injected CO2 as no more oil was produced. The measured accumulative producing gas-oil ratio (GOR) versus the injected P.V. of CO2 is shown in Figure 7b. It is noticed that the producing GOR was extremely low before CO2 breakthrough but increased drastically after CO2 breakthrough. Moreover, a higher injection pressure generally resulted in a much higher GOR at 2.0 P.V. of injected CO2. The ultimate oil recovery factor of each CO2 coreflood test versus the injection pressure at 2.0 P.V. of injected CO2 is summarized in Table 3 and plotted in Figure 7c. More specifically, at P = 4.8-7.4 MPa, the oil RF increases substantially. The increased oil recovery with the injection pressure is attributed to the increased solubility of CO2 in oil, increased viscosity of injected CO2, and reduced equilibrium IFT of the light crude oil-CO2 system in this low pressure range. When the injection pressure exceeds 7.4 MPa, the oil RF reaches its maximum and remains almost constant. In this case, the ultimate oil RF reaches a plateau in the range of 7.4 MPa e P e 14.0 MPa. Also, as described in the previous section, the equilibrium IFT between the crude oil and CO2 remains low but almost constant if the equilibrium pressure is higher than the MMP (i.e., 7.5-7.6 MPa); see Figure 5. Therefore, it is the multicontact miscibility and possibly the low but almost constant equilibrium IFT together that make the ultimate oil RF high but almost constant in this high pressure range.8,25 With the measured stable differential pressures during the initial original light crude oil injection and its final reinjection, the oil effective permeability reduction is calculated for each coreflood test in the CO2 secondary oil recovery process. This permeability reduction is mainly attributed to the asphaltene deposition, in conjunction with a small amount of metal carbonate deposition.4,26 The calculated oil effective permeability reduction data in percentages for all CO2 secondary oil recovery tests (Tests #1-7) are listed in Table 3. Figure 7c shows the oil effective permeability reduction with CO2 injection pressure. It can be seen from this figure that if the injection pressure is lower than 7.4 MPa, the oil effective permeability reduction is relatively small (below 10%) but gradually increases as the injection pressure increases from 4.8 to 7.4 MPa. If the injection pressure is equal to or higher than 7.4 MPa (i.e., the miscible case), the oil effective permeability reduction is over 10% but remains nearly the same. In addition, the asphaltene content of CO2-produced oil in each test is listed in Table 3 and also plotted in Figure 7c. It is found that the asphaltene content of CO2-produced oil is always lower than that of the original light crude oil. The asphaltene content of CO2-produced oil decreases substantially as the injection pressure increases from 4.8 to 7.4 MPa and then reaches a plateau at P g 7.4 MPa (i.e., the miscible case). This indicates that, in the immiscible CO2 flooding process (P < 7.4 MPa), more precipitated asphaltenes are left in the reservoir core plugs at a higher injection pressure. This causes a larger oil effective

ARTICLE

Figure 8. (a) Measured oil recovery factor of CO2 and/or water flooding versus the injected P.V. of CO2 or water at qco2= 0.4 cc/min or qwater= 0.4 cc/min, P = 12.0 MPa, and T = 27 °C. (b) Measured accumulative producing WOR or GOR of CO2 and/or water flooding versus the injected P.V. of CO2 or water at qco2= 0.4 cc/min or qwater = 0.4 cc/min, P = 12.0 MPa, and T = 27 °C. (c) Measured asphaltene content of CO2-produced oil, oil recovery factor, and oil effective permeability reduction after CO2 dry, secondary, and tertiary flooding at 2.0 P. V. of injected CO2, qco2= 0.4 cc/min, P = 12.0 MPa, and T = 27 °C.

permeability reduction. In the miscible CO2 flooding process (P g 7.4 MPa), the amount of precipitated asphaltenes left in the reservoir core plugs reaches its largest value, which results in the largest oil effective permeability reduction. In summary, it is seen from Figure 7c that, in the miscible CO2 flooding process, both the oil RF and oil effective permeability reduction reach their largest values, whereas the asphaltene content of CO2-produced oil reaches its lowest value. In this case, injected CO2 effectively displaces most oil to achieve the highest oil RF, in contrast to the 2396


Industrial & Engineering Chemistry Research immiscible case. On the other hand, the most severe asphaltene precipitation and deposition leads to the largest amount of precipitated asphaltenes left in the reservoir core plugs and the largest oil effective permeability reduction. 3.5. CO2 Miscible Flooding. In this work, three different miscible CO2 coreflood tests (P g MMP) were conducted through the respective dry, secondary, and tertiary oil recovery processes to study the effects of an oil recovery process on the oil RF, producing WOR and GOR, asphaltene content of the produced oil, and oil effective permeability reduction. The detailed experimental data of Tests #8 (dry), #6 (secondary), and #9 (tertiary) are listed in Table 3. These three tests were performed at CO2 injection pressure of P = 12.0 MPa and a constant temperature of T = 27 °C. The CO2 dry and secondary oil recovery tests (Tests #8 and #6) were performed at a constant volume injection rate of qco2= 0.4 cc/min. In the CO2 tertiary oil recovery test (Test #9), water flooding was conducted at qwater= 0.4 cc/min and then followed by CO2 tertiary flooding at qco2= 0.4 cc/min. Figure 8a shows the measured oil RF versus the injected P.V. of CO2 or water for three different production processes. It can be seen from this figure that, before 0.5 P.V., the oil RF of waterflooding test is higher than those of two CO2 flooding tests. After 0.5 P.V., the oil RF of water flooding achieved its highest value until the end of water flooding at 1.5 P.V., while the oil RFs of the two CO2 flooding tests still keep increasing until a much higher RF is reached. It is also found that the total oil RF for the secondary water flooding and CO2 tertiary flooding is much lower than that for CO2 dry or secondary flooding. This implies that, in practice, CO2 secondary flooding may have a considerably higher oil RF than the total oil RF for the secondary water flooding and CO2 tertiary flooding. A slightly lower oil RF in the CO2 dry oil recovery test (Test #8) than that in the CO2 secondary oil recovery test (Test #6) is due to its much lower absolute permeability, which has a strong effect on CO2 miscible flooding. The measured accumulative producing water-oil ratio (WOR) and gas-oil ratio (GOR) versus the injected P.V. of water or CO2 are plotted in Figure 8b. It can be seen from this figure that, prior to water breakthrough at 0.4 P.V., the producing WOR in Test #9 is extremely low, whereas it increases dramatically after water breakthrough. Similar trends for the producing GOR in CO2 dry (Test #8) and secondary (Test #6) oil recovery processes are also found. During the CO2 tertiary oil recovery process (Test #9), the producing GOR remains low at 1.52.5 P.V. of injected CO2 and then gradually increases up to 210 mL CO2/mL oil. In the previous section, Figure 6a-c shows the measured differential pressure versus the injected P.V. of the original crude oil/water/CO2 during the initial original light crude oil injection, water flooding, CO2 flooding, and final original light crude oil reinjection for three different miscible CO2 coreflood tests (Tests #8, #6, and #9) at P = 12.0 MPa. It is found that the increase of the differential pressure from the initial original light crude oil injection to its final reinjection is the largest in the CO2 tertiary oil recovery process (Test #9) among the three tests. The calculated oil effective permeability reduction data for the three different miscible CO2 coreflood tests are listed in Table 3 and compared in Figure 8c. This figure indicates that the oil effective permeability reduction becomes the largest in the secondary water flooding and subsequent CO2 tertiary flooding. This is because, in this case, both asphaltenes and several metal carbonates are

ARTICLE

Figure 9. Produced oil, metal carbonates, and brine after CO2 tertiary oil recovery in Test #9.

precipitated and deposited onto the reservoir core plugs as injected CO2 contacts the residual oil and there is a large amount of the remaining water after water flooding. The carbonated brine can react with Ca2þ and Mg2þ to form CaCO3 and MgCO3, which are deposited onto the reservoir sand grains.4 Therefore, Test #9 has the largest oil effective permeability reduction after CO2 tertiary oil recovery. Test #6 at a much lower initial connate water saturation has a much smaller oil effective permeability reduction after CO2 secondary oil recovery. Test #8 gives the smallest oil effective permeability reduction after CO2 dry flooding, which is attributed to the asphaltene deposition alone in this flooding process. Furthermore, the asphaltene contents of CO2-produced oil samples in the three different miscible production processes are shown in Figure 8c. It can be seen from this figure that the asphaltene content of CO2-produced oil in Test #9 has the highest value. This is because the measured nominal “asphaltene content” using the standard ASTM D2007-0313 method includes precipitated asphaltenes and possible metal carbonates in CO2-produced oil, as shown in Figure 9. The produced oil in Test #6 with a much lower initial connate water saturation has a much lower “asphaltene content”, in comparison with that in Test #9. Moreover, in the absence of the water, the asphaltene content of CO2-produced oil during CO2 dry oil recovery (Test #8) has the lowest value due to the asphaltenes precipitation alone. There is no precipitation of metal carbonates in this case. In general, because the secondary water flooding significantly increases the water saturation, a large amount of metal carbonates is precipitated and deposited onto the reservoir core plugs to cause the largest oil effective permeability reduction for CO2 tertiary oil recovery. Meanwhile, a considerable portion of metal carbonates is produced with oil and measured as “asphaltene content”. It is also found that the total oil RF for Test #9 is much lower than that for Test #8 or #6. This finding further indicates that the secondary water flooding followed by the subsequent CO2 tertiary flooding is less effective in terms of the oil recovery than CO2 secondary flooding and can result in much more severe reservoir formation damage due to coprecipitation and codeposition of asphaltenes and much more metal carbonates as well.

4. CONCLUSIONS In this paper, a light crude oil-CO2 system is tested in a seethrough windowed high-pressure saturation cell to determine its 2397


Industrial & Engineering Chemistry Research onset pressure of asphaltene precipitation. It is found that the onset pressure of asphaltene precipitation is equal to 4.8 MPa. Then, the equilibrium IFTs between the crude oil and CO2 are measured at 12 different equilibrium pressures and T = 27 °C using the ADSA technique for the pendant drop case to determine the MMP. It is found that the measured equilibrium IFT is reduced almost linearly with the equilibrium pressure in three rather different pressure ranges. The linear regression equations of the measured equilibrium IFT versus equilibrium pressure data for the first two different pressure ranges converge to an almost same equilibrium pressure (P = 7.5-7.6 MPa) at zero equilibrium IFT, which is considered as the MMP obtained using the VIT technique. Furthermore, a series of nine CO2 coreflood tests is conducted to study the oil recovery and permeability reduction of a tight sandstone reservoir under immiscible and miscible conditions and through three different production processes, namely, CO2 dry, secondary, and tertiary oil recovery. In the CO2 secondary oil recovery process, it is found that, when the injection pressure is between the onset pressure of asphaltene precipitation and the MMP, the oil RF becomes higher at a higher pressure during the immiscible CO2 flooding. It reaches an almost constant maximum value in the miscible CO2 flooding (P g MMP). A similar trend is found for the oil effective permeability reduction but the measured asphaltene content of CO2-produced oil has an opposite trend. In three miscible CO2 oil recovery processes, the measured “asphaltene content” of produced oil in the CO2 tertiary oil recovery process has the highest value, which is attributed to a large amount of metal carbonates along with CO2-produced oil. In addition, the oil effective permeability reduction of the CO2 tertiary oil recovery process achieves its largest value, and its total oil RF is the lowest due to the most severe codeposition of asphaltenes and some metal carbonates. Hence, it can be concluded that, in practice, the secondary water flooding followed by the subsequent CO2 tertiary flooding may be less effective and cause much more severe formation damage in a tight light oil reservoir than direct CO2 secondary flooding.

’ AUTHOR INFORMATION Corresponding Author

*Tel.: 1-306-585-4630. Fax: 1-306-585-4855. E-mail: Peter. [email protected].

’ ACKNOWLEDGMENT The authors acknowledge the discovery grant from the Natural Sciences and Engineering Research Council (NSERC) of Canada and the innovation fund from the Petroleum Technology Research Centre (PTRC) at the University of Regina to Y. Gu. The authors also wish to thank Mr. Shiyang Zhang at the University of Regina for his technical assistance in the high-pressure interfacial tension measurements and CO2 coreflood tests. ’ REFERENCES (1) Aycaguer, A. C.; Lev-On, M.; Winer, A. M. Reducing Carbon Dioxide Emissions with Enhanced Oil Recovery Projects: A Life Cycle Assessment Approach. Energy Fuels 2001, 15 (2), 303–308. (2) Chung, F. T. H.; Jones, R. A.; Burchfield, T. E. Recovery of Viscous Oil under High Pressure by CO2 Displacement: A Laboratory Study. Presented at SPE International Meeting on Petroleum Engineering, Tianjin, China, November 1-4 1988; Paper SPE 17588.

ARTICLE

(3) Kokal, S. L.; Sayegh, S. G. Asphaltenes: The Cholesterol of Petroleum. Presented at SPE Middle East Oil Show, Manama, Bahrain, March 11-14, 1995; Paper SPE 29787. (4) Sayegh, S. G.; Krause, F. F.; Girard, M.; Debree, C. Rock/Fluid Interactions of Carbonated Brines in a Sandstone Reservoir: Pembina Cardium. SPE Format. Eval. 1990, 5 (4), 399–405. (5) Przybylinski, J. L. The Role of Bicarbonate Ion in Calcite Scale Formation. SPE Prod. Eng. 1987, 2 (1), 63–67. (6) Speight, J. G. Handbook of Petroleum Analysis; John Wiley & Sons, Inc.: New York, 2001. (7) Luo, P.; Yang, C.; Tharanivasan, A. K.; Gu, Y. In-situ Upgrading of Heavy Oil in a Solvent-based Heavy Oil Recovery Process. J. Can. Pet. Technol. 2007, 46 (9), 37–43. (8) Nobakht, M.; Moghadam, S.; Gu, Y. Mutual Interactions between Crude Oil and CO2 under Different Pressures. Fluid Phase Equilib. 2008, 265 (1&2), 94–103. (9) Mansoori, G. A.; Vazquez, D.; Shariaty-Niassar, M. Polydispersity of Heavy Organics in Crude Oils and Their Role in Oil Well Fouling. Fluid Phase Equilib. 2006, 58 (3&4), 375–390. (10) DeBoer, R. B.; Leerlooyer, K.; Eigner, M. R. P.; van Bergen, A. R. D. Screening of Crude Oils for Asphalt Precipitation: Theory, Practice, and the Selection of Inhibitors. SPE Prod. Facil 1995, 10 (1), 55–61. (11) Sarma, H. K. Can We Ignore Asphaltene in a Gas Injection Project for Light-Oils? Presented at SPE International Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, October 20-21, 2003; Paper SPE 84877. (12) Hamouda, A. A.; Chukwudeme, E. A.; Mirza, D. Investigating the Effect of CO2 Flooding on Asphaltenic Oil Recovery and Reservoir Wettability. Energy Fuels 2009, 23 (2), 1118–1127. (13) ASTM D2007-03, Standard Test Method for Characteristic Groups in Rubber Extender and Processing Oils and Other PetroleumDerived Oils by the Clay-Gel Absorption Chromatographic Method; ASTM International: West Conshohocken, PA, 2007. (14) ASTM D86, Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure; ASTM International: West Conshohocken, PA, 2003. (15) Peng, D. Y.; Robinson, D. B. A New Two-constant Equation of State. Ind. Eng. Chem. Fundam. 1976, 15 (1), 58–64. (16) Escobedo, J.; Mansoori, G. A. Viscometric Determination of the Onset of Asphaltene Flocculation: A Novel Method. SPE Prod. Facil. 1995, 10 (2), 115–118. (17) Vuong, L. T. Asphaltene Deposition and Its Role in Enhanced Oil Recovery (EOR) Miscible Gas Flooding Process. Master Thesis, Department of Chemical Engneering, Univeristy of Illinois at Chicago, Chicago, IL, 1985. (18) Cheng, P.; Li, D.; Boruvka, L.; Rotenberg, Y.; Neumann, A. W. Automation of Axisymmetric Drop Shape Analysis for Measurements of Interfacial Tensions and Contact Angles. Colloids Surf. 1990, 43 (2), 151–167. (19) Hirschberg, A.; Dejong, L. N.; Schipper, B. A.; Meijer, J. G. Influence of Temperature and Pressure on Asphaltene Flocculation. SPE J. 1984, 24 (3), 283–293. (20) Yang, D.; Tontiwachwuthikul, P.; Gu, Y. Interfacial Tensions of the Crude Oil þ Reservoir Brine þ CO2 Systems at Pressures up to 31 MPa and Temperatures of 27°C and 58°C. J. Chem. Eng. Data 2005, 50 (4), 1242–1249. (21) Nobakht, M.; Moghadam, S.; Gu, Y. Determination of CO2 Minimum Miscibility Pressure from the Measured and Predicted Equilibrium Interfacial Tensions. Ind. Eng. Chem. Res. 2008, 47 (22), 8918–8925. (22) Wang, X.; Zhang, S.; Gu, Y. Four Important Onset Pressures for Mutual Interactions between Each of Three Crude Oils and CO2. J. Chem. Eng. Data 2010, 55 (10), 4390–4398. (23) Rao, D. N.; Lee, J. I. Application of the New Vanishing Interfacial Tension Technique to Evaluate Miscibility Conditions for the Terra Nova Offshore Project. J. Pet. Sci. Eng. 2002, 35 (3&4), 247–262. 2398



ARTICLE

(24) Rao, D. N.; Lee, J. I. Determination of Gas-Oil Miscibility Conditions by Interfacial Tension Measurements. J. Colloid Interface Sci. 2003, 262 (2), 474–482. (25) Nobakht, M.; Moghadam, S.; Gu, Y. Effects of Viscous and Capillary Forces on CO2 Enhanced Oil Recovery under Reservoir Conditions. Energy Fuels 2007, 21 (6), 3469–3476. (26) Srivastava, R. K.; Huang, S. S.; Dong, M. Asphaltene Deposition during CO2 Flooding. SPE Prod. Facil. 1999, 14 (4), 55–61.

2399


Oil Recovery and Permeability Reduction of a Tight Sandstone

Recommend Documents