Investigating the Effect of CO2 Flooding on Asphaltenic Oil Recovery

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Energy & Fuels 2009, 23, 1118–1127

Investigating the Effect of CO2 Flooding on Asphaltenic Oil Recovery and Reservoir Wettability A. A. Hamouda,* E. A. Chukwudeme, and D. Mirza† Department of Petroleum Engineering, UniVersity of StaVanger, 4036 StaVanger, Norway ReceiVed October 15, 2008. ReVised Manuscript ReceiVed December 26, 2008

Miscible and immiscible flooding with CO2 of oils containing asphaltene for chalk reservoir is investigated. Oil recovery from model oil and crude oil (30° API gravity), containing 0.35 and 10 wt % asphlatene, respectively, is addressed. n-Decane is used as a reference oil and showed an increase of recovery from 81 to 89% at 50 °C and 90 bar and 80 °C and 140 bar, respectively. Both model and crude oils showed a reduction in the oil recovery from 78.92 to 70.4% and from 37.6 to 36.6%, respectively, at the same conditions as that for the reference oil. The insignificant change in the oil recovery between the two conditions for the crude oil may be due to the high asphaltene content (10%). A model based on the solubility theory is developed to account for the effect of CO2 flooding and is verified using literature data for CO2 flooding. The average deviations of the model for the miscible flooding from the experimental are 15 and 18% for this study and literature data, respectively. The relative contribution of CO2 on asphaltene precipitation because of miscible CO2 flooding is compared to that for the pressure and temperature effect. On the basis of the approach in this work and available data from literature, CO2 critical content lies between 42 and 17 mol % in the liquid phase, with an average value of about 33 mol %.

Introduction Gas injections in enhanced oil recovery (EOR) processes in most reservoirs have been encouraging, especially for light oil reservoirs with CO2 gas injection, as one of the most attractive proposed methods to enhance oil recovery.1,2 Hadlow3 has shown that the incremental production response to CO2 injection has been outstanding. Grigg and Schechter4 reviewed 25 CO2 projects and concluded that CO2 flooding provides a good increment in EOR. It is known that CO2 injection can lead to asphaltene deposition, resulting in the plugging of the formation (pore channels), wellbore (production tube), and production facilities (transport lines, separators, etc.). Many investigations have been performed in the literature to address the aggregation and solubility of asphaltene in crude oil. The solubility of asphaltene depends upon the mutual balance between the asphaltene fraction and the lighter fractions of the crude oil. Any unfavorable condition will result in destabilization of asphaltene equilibria. Conditions such as the dilution of petroleum fluids with low-molecular-weight alkanes, gases, or CO2 initiate asphaltene precipitation. CO2 destabilizes the dissolved asphaltene in the oil. Therefore, a systematic investigation of pressure, temperature, and compositional changes during CO2 injection on precipitation of asphaltene helps to better understand * To whom correspondence should be addressed. Telephone: +47-5183-22-71. Fax: +47-51-83-17-50. E-mail: [email protected]. † Current address: Logtek, 4068 Stavanger AS, Norway. (1) Moritis, G. EOR survey. Oil Gas J. 2002, 100 (15), 43–47. (2) Moritis, G. EOR continues to unlock oil resources. Oil Gas J. 2004, 102 (14), 45–65. (3) Hadlow, R. E. Update of industry experience with CO2 injection. Paper presented at the 1992 Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition, Washington, D.C., Oct 4-7, 1992; SPE 24928. (4) Grigg, R. B.; Schechter, D. S. State of the industry in CO2 floods. Paper presented at the 1997 Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition, San Antonio, TX, Oct 5-8, 1997; SPE 38849.

the precipitation/deposition mechanisms and the contribution of the different parameters in this process. Simon et al.,5 Burke et al.,6 and Werner et al.7 reported that the CO2 injection is a determining factor for asphaltene precipitation. Idem and Ibrahim8 observed in their studies that the rate of asphaltene precipitation depends upon both the asphaltene and CO2 contents in the oil as well as temperature. De Boer et al.9 concluded that light to medium crude oils containing small amounts of asphaltenes may create more asphaltene precipitation problems during primary production. Haskett and Tartera10 reported a similar observation that reservoir oils with low asphaltene content are susceptible to asphaltene precipitation because of not only pressure depletion during primary recovery but also composition changes in the fluid during gas injection. Kulkarni and Rao11 stated that the main design parameters on a laboratory scale to evaluate the feasibility of gas injection depend upon reservoir heterogeneity, rock type, fluid characteristics, injection gas, WAG ratio, gravity considerations, as well as miscibility development and composition of oil and brine. Lasne et al.12 have demonstrated in an investigation on synthetic crudes that the asphaltene precipitation does not only depend upon the gas concentration but also the aromaticity of the petroleum fluid. (5) Simon, R.; Rosman, A.; Zana, E. J. SPE J. 1978, 18 (1), 20–26. (6) Burke, N. E.; Hobbs, R. E.; Kashou, S. F. J. Pet. Technol. 1990, 1440–1446. (7) Werner, A.; Behar, F.; De Hemptinne, J. C.; Behar, E. Org. Geochem. 1996, 24 (10-11), 1079–1095. (8) Idem, R. O.; Ibrahim, H. H. J. Pet. Sci. Eng. 2002, 35, 233–246. (9) DeBoer, R. B.; Leerlooyer, K.; Eigner, M. R. P.; Van Bergen, A. R. D. SPE Prod. Facil. 1995, 55, 61. (10) Haskett, C. E.; Tartera, M. J. Pet. Technol. 1965, 387–391. (11) Kulkarni, M. M.; Rao, D. N. J. Pet. Sci. Eng. 2005, 48, 1–20. (12) Lasne, D.; Barreau, A.; Behar, E. Phase behaviour laboratory investigation of CO2-hydrocarbon mixtures for enhanced oil recovery modelling. Proceedings of the 4th European Symposium on Enhanced Oil Recovery, Hamburg, Germany, Oct 27-29, 1987.

10.1021/ef800894m CCC: $40.75  2009 American Chemical Society Published on Web 02/02/2009

CO2 Flooding on Asphaltenic Oil RecoVery

Energy & Fuels, Vol. 23, 2009 1119

Table 1. Core Descriptions and Its Associated Fluid Composition core dry weight porosity number L (cm) (g) (%) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 a

6.90 7.00 7.00 7.10 7.10 7.00 7.00 7.20 7.00 7.20 7.00 7.10 6.90 7.00 7.00 7.00 6.95 7.00 7.00 6.90 6.95

115.77 117.11 118.13 111 110.8 110.1 110.79 114.39 113.83 118.29 116.85 112.05 111.07 118.17 117.37 115.74 116.71 114.03 114.75 114.75 114.72

46.4 44.4 44.7 45.6 45.9 45.3 45.5 47.1 46.8 44.8 44.2 47.7 46 45.3 44.7 45.9 44 43.9 44.5 45.1 45.2

saturating fluid n-C10 n-C10 n-C10 model oil model oil model oil model oil model oil model oil model oil model oil model oil model oil crude oil crude oil crude oil DW/model oil 0.06 M Mg2+/model oil 0.03 M SO42-/model oil 0.06 M Mg2+ + 0.03 M SO42-/model oil 0.06 M Mg2+ + 0.03 M SO42-/model oil

asphaltene pressure (bar) and content in feed CO2 moles oil (wt %) Swi (%) Sor (%) injected (mol %) temperature (°C) 18.38 13.40 10.94

23.61 23.92 23.63 23.43 22.73

26.65 32.85 17.59 21.04 30.47 21.89 20.27 64.44 63.10 62.36 31.71 28.42 27.44 23.54 23.89

93.53 88.79 89.53 50a 70a 84.47a 80.38 76.80 79.19 85.20 86.65 87.62 88.04 85.12 89.58 89.58 86.60 69.97 54.38 70.14 61.70

90 and 50 120 and 70 140 and 80 20 and 25 20 and 25 20 and 25 140 and 80 140 and 80 120 and 70 120 and 70 120 and 70 90 and 50 90 and 50 140 and 80 120 and 70 90 and 50 90 and 50 90 and 50 90 and 50 90 and 50 90 and 50

0.50 0.50 0.50 0.35 0.35 0.35 0.35 0.35 0.35 0.35 10 10 10 0.35 0.35 0.35 0.35 0.35

Immiscible CO2 flooding process.

Table 2. Chemical Analysis of Stevns Klint Chalk (Strand et al.27) elements content

wt %

Mg AL Si K Ca total

0.69 0.47 1.44 0 97.42 100

Wilhelms13 reported that the principal factors governing the volume fraction of asphaltenes soluble in a crude oil are the crude oil (solvent) solubility parameter, the temperature, and the molar volumes of the solvent (crude oil) and that of asphaltene. Different models have been developed taking into account the following approaches: (1) thermodynamic molecular solubility model, (2) thermodynamic colloidal model, (3) thermodynamic micellization model, and (4) solid line model. Hirschberg et al.14 developed a method on the basis of the solubility model using the Flory-Huggins15 approach. They proposed a simple thermodynamic model based on the influence of temperature and pressure on asphaltene precipitation during natural depletion. In this model, the oil is considered to be a binary mixture of two components: a component that corresponds to asphaltene and the solvent (deasphalted oil). They stated that the Flory-Huggins model is not accurate for asphaltene prediction. Gupta16 developed a model using a single-component solid model, in which the precipitated asphaltene is represented as a pure solid, while the oil and gas phases are modeled with a cubic equation of state (EOS). This model contains large numbers of parameters to be tuned to match the experimental data. Leontaritis and Mansoori17 on the other hand, proposed a thermodynamic colloidal model assuming that asphaltene exist in the oil as solid particles in colloidal suspension, stabilized (13) Wilhelms, A. Ph.D. Thesis, Department of Geology, University of Oslo, Oslo, Norway, 1992. (14) Hirschberg, A.; De Jong, L. N. J.; Schipper, B. A.; Meyers, J. G. SPE J. 1984, 283–293. (15) Prausnitz, J. M. Molecular Thermodynamics of Fluid-Phase Equilibria; Prentice Hall: Upper Saddle River, NJ, 1969. (16) Gupta, A. K. M.Sc. Thesis, Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, Alberta, Canada, 1986.

by resins adsorbed on their surface. Later, Kawanaka et al.18 extended the homogeneous polymers approach of Hirschberg et al.,14 considering asphaltenes to be heterogeneous polymers improving the fit, although with an increase in the number of parameter to be tuned. Thomas et al.19 introduced an empirical solid model, considering the precipitated asphaltene as a multicomponent solid using the liquid-solid wax model of Won,20 leading to a large number of parameters to be specified. Yang et al.21 proposed a modified Hirschberg solubility model based on their perceived inadequacies of the original Hirschberg solubility model, and it was emphasized that the oil phase should be treated as a multicomponent mixture. Pan and Firoozabadi22,23 also developed a thermodynamic model based on the micellization process and direct minimization of the Gibbs free energy to describe asphaltene aggregation and precipitation in crude oils. The predicted results follow the experimentally observed trend, but computation demands a large number of parameters. Nghiem et al.24 proposed a thermodynamic solid model to determine the dynamic aspect of asphaltene precipitation using a compositional simulator during primary oil recovery and CO2 flooding. Paricaud et al.25 applied a simplified statistical association theory (SAFT) description of the thermodynamics of chain molecules used to model the limit of stability of polymer-colloid systems. A modified version of statistical association theory (SAFT) EOS derived by Chapman and co(17) Leontaritis, K. J.; Mansoori, G. A. Asphaltene flocculation during oil production and processing: A thermodynamic collodial model. Paper presented at the SPE International Symposium on Oil Field Chemistry, San Antonio, TX, Feb 4-6, 1987; SPE 16258. (18) Kawanaka, S.; Park, S. J.; Mansoori, G. A. SPE ReserVoir EVal. Eng. 1991, 6, 185–192. (19) Thomas, F. B.; Bennion, D. B.; Bennion, D. W.; Hunter, B. E. Can. J. Pet. Technol. 1992, 31, 22–31. (20) Won, K. W. Fluid Phase Equilib. 1986, 30, 265–279. (21) Yang, Z.; Ma, C. F.; Lin, X. S.; Yang, J. T.; Guo, T. M. Fluid Phase Equilib. 1999, 157, 43–158. (22) Pan, H.; Firoozabadi, A. SPE Prod. Facil. 1998, 13, 118–127. (23) Pan, H.; Firoozabadi, A. SPE Prod. Facil. 2000, 15 (1), 58–65. (24) Nghiem, L. X.; Coombe, D. A.; Ali, F. Compositional simulation of asphaltene deposition and plugging. Paper presented at the SPE 73rd Annual Technical Conference and Exhibition, New Orleans, LA, Sept 2730, 1998; SPE 48996. (25) Paricaud, P.; Galindo, A.; Jackson, G. Fluid Phase Equilib. 2002, 194, 87–96.

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Table 3. Oil Composition as Reported in the Literature and This Work Used for CO2 Flooding Experiments components N2 CO2 H2S C1 C2 C3 i-C4 n-C4 2,2-DM-C3 i-C5 n-C5 C6 C7 toulene C7+ C8 C9 C6-C9 C10 C10+ C10-C17 C11 C11+ C12+ C18 stearic acid C18-C27 C28+ PS1 PS2 PS3 resin (wt %) asphaltene (wt %) a

oil 1 (mol %) (this work)

oil 2 (mol %) heavy crude (this work)

0.02 0.63 0.51 2.34 0.01 2.32 3.51 6.28 6.7

oil 3 (mol %)28

oil 4 (mol %)29

0.57 2.46

0.96 0.16

36.37 3.47 4.05 0.59 1.34

24.06 0.76 3.26 0.64 2.7

0.74 0.83 1.62

0.52 1.06 0.7 0.58

oil 5 (mol %)22

oil 6 (mol %)30

0.96 0.58 0.3 4.49 2.99 4.75 0.81 1.92

0.1 3.71 1.85 46.53 8.76 4.98 0.93 2.39

1.27 2.19

0.86 1.06 2.64 2.73

47.31 6.7 5.77

1.86 2.3

1.31 2.19 25.73 (105)a

52.601

0.82

1.67

65.21 (287.38)a 26.98 (179)a 1.52 52.91 (442)a 16.77 (260)a 0.048 (284.29)a

0.041 (1000)a

18.20 (142.0)a 13.98 (274.0)a 3.690 (350.9)a 8.930 (603.0)a 3.170 (850)a

13.28 (312)a 13.75 (576)a 6.69 (442)a 4.359 (582)a 4.89 1.82

1.839 (850)a 0.862 (1000)a

The corresponding molecular-weight values are given in parentheses.

developed to account for the effect of CO2 flooding on asphaltene precipitation. Experimental Section

Figure 1. MMP values (in bar) obtained from different empirical correlations and PVT sim (used in this study) for temperatures of 50, 70, and 80 °C.

workers26 was proposed considering the effect of the molecular shape, van der Waals interaction, and aggregation of molecules. This model has proven to be a very powerful approach in the prediction of the phase behavior of polydisperse polymers. In this paper, the combined effect of pressure and temperature during CO2 injection on asphaltene precipitation and the presence of initial water saturation (DW, 0.06 M Mg2+, 0.03 M SO42-, and a combination of 0.06 M Mg2+ and 0.03 M SO42-) on oil recovery is investigated. A model approach is (26) Chapman, W. G.; Sauer, G. S.; Ting, D.; Ghosh, A. Fluid Phase Equilib. 2004, 217, 137–143.

Materials. Solid Phase. A total of 21 outcrop carbonate chalk cores of 6.9-7 cm in length and 3.8 cm in diameter with an approximate porosity of 44-48% and absolute permeability of 3-5 mD obtained from Stevns Klint near Copenhagen, Denmark, were used. Table 1 is the core-detailed description and its associated fluid content. EDS analyses on Stevns Klint have been performed by Strand et al.27 The results are presented in Table 2 as an average value of three EDS analyses from three different chalk blocks. Oil Phase. The investigations are performed on three types of oils: (a) n-decane (reference), (b) model oil (0.35-0.5 wt % asphaltene dissolved in toluene and 0.005 M stearic acid (SA) dissolved in n-decane (95% purity), oil 1, and (c) crude oil (Middle East), oil 2. Table 3 shows the composition of oils 1-6, which are model oil, crude oil, Vafaie-Sefti et al.,28 Hu et al.,29 Pan et al.,22 and Moghagadsi et al.,30 respectively. Oil Model Preparation Procedure. The model oil system is prepared from asphaltene precipitated from crude oil in excess of n-heptane (1:40). The mixture was shaken at least twice a day and left for 48 h to equilibrate. The mixture solution was then (27) Strand, S.; Hjuler, M. K.; Torsvik, R.; Pedersen, J. I.; Madland, M. V.; Austad, T. Pet. Geosci. 2007, 13 (1), 69–80. (28) Vafaie-Sefti, M.; Mousavi-Dehghani, S. A. Fluid Phase Equilib. 2006, 247, 182–189. (29) Hu, Y.; Shi, L.; Ning, L.; Yan-Ping, C.; Sang, J. P.; Mansoori, G. A.; Guo, T. J. Pet. Sci. Eng. 2004, 41, 169–182. (30) Moghadasi, J.; Kalantari-Dahaghi, A. M.; Gholami, V.; Abdi, R. Formation damage due to asphaltene precipitation resulting from CO2 gas injection in Iranian carbonate reservoirs. Paper presented at the 2006 SPE Europe/EAGE Annual Conference and Exhibition, Vienna, Austria, June 12-15, 2006; SPE 99631.



Figure 2. Schematic of the CO2 flooding setup.

centrifuged and filtered through a 0.22 µm filter (Millipore) and dried for 1 day using a vacuum oven at room temperature. The dried asphaltenes was then dissolved in toluene and mixed with n-decane containing 0.005 M SA to obtain the model oil used in this work. Afterward, the model oil was filtered to remove the suspended materials. Minimum Miscibility Pressure (MMP). MMP is investigated using SRK-Peneloux EOS, PVTsim version 17 and empirical correlations by Alston et al.,31 Yelling and Metcalfe,32 Glasø,33 and Johnson and Pollin.34 The estimated MMPs for the used oils at temperatures of 50, 70, and 80 are shown in Figure 1. PVTsim data are shown to lie in the middle and are used in this work. Experimental Setup. The schematic flow diagram of the experimental setup used for studying the asphaltenic oil recovery in CO2-injected oil systems is presented in Figure 2. The major components of the experimental setup consist of a core holder, pressure regulator, two gas flow meters, pressure manometers, Gilson pump, three piston cells (two CO2 piston cells and oil sample cell), graduated gas/oil separator, and a labview version 7.1 connected to a monitor. Oil-saturated core samples were inserted into a horizontally placed core holder that consists of a steel cylindrical body and rubber/Teflon sleeve. A net overburden pressure of 20 bar is applied on the sleeve. Then, CO2 injection was carried out in two modes, namely, immiscible and miscible flooding. In the Immiscible process, approximately a 57 g mixture solution of oil 1 was charged into the oil sample cell and flooded into the core at a flow rate of 0.5 mL/min using Gilson pump (806 manometric modules) simultaneously with CO2. Whereas, in the miscible mode, the model oil-saturated core was flooded with CO2 (not simultaneously injected as in the immiscible flooding experiment). CO2 was injected into the core at a constant pressures of 20 ( 0.2 bar and temperatures of 25 °C and 90-140 ( 0.2 bar and 50-80 °C for immiscible and miscible processes, respectively. CO2 is injected from a piston cell via a flow meter (1) that records the in-flow properties of CO2 (mass flow rate, density, and total mass). A back-pressure regulator is installed (31) Alston, R. B.; Kokolis, G. P.; Jams, C. F. SPE J. 1985, 25 (2), 268–274. (32) Yelling, W. F.; Metcalfe, R. S. J. Pet. Technol. 1980, 160, 68. (33) Glasø, Ø. SPE J. 1985, 25 (66), 927–935. (34) Johnson, J. P.; Pollin, J. S. Measurement and correlation of CO2 miscibility pressure. SPE/ODE 9790, 1980; pp 269-273.

downstream from the core to control the pressure during CO2 flooding. The produced fluid from the core was collected in a graduated gas/oil separator, where the fluid stream was separated to liquid and CO2 gas. CO2 gas was stored in a piston cell and not discharged into the atmosphere. The out-flow properties (mass flow rate, density, and total mass) of the evolved gas were also recorded using a flow meter (2) connected to the separator. The CO2 injection continued for at least three pore volumes until there was no oil production. When the injection was terminated, the core was then removed from the core holder and dried using a vacuum oven at a temperature of 120 °C, until a constant weight was obtained. Some selected cores after obtaining a constant weight were crushed and put into the oven under vacuum to increase the surface area exposed to the heat and vacuum. This showed an insignificant difference (about 0.5%) between the stable weight of the dried cores with heat and under vacuum and with that obtained from the stable weight of the crushed cores with heat and under vacuum. The amount of asphaltene precipitated was estimated from the mass balance of the dried core before the saturation process and after the termination of the flooding. Model Description. The solubility model is considered in this work, because it is generally believed that the solubility of the asphaltene decreases as a result of gas injection, which is being dissolved in the oil. The dissolved asphaltene volume fraction in the fluid at a given condition is determined by eq 114

[

φA ) exp

VA VA - 1 - (δA - δL)2 VL RT

]

(1)

where φA is the volume fraction that can be dissolved in the liquid (in equilibrium with the solid phase) at given conditions, VA and VL are the molar volume of the asphaltene and liquid phase, respectively, δA and δL are the solubility parameters of the asphaltene and liquid phase, respectively, T represents temperature, and R is the gas constant. The weight fraction of asphaltene precipitated can be calculated by

WFA ) WA/WTL ) (WTAL - WAL)/WTL

(2)

where WFA is the weight fraction of asphaltene precipitated, WA is the weight (g) of asphaltene precipitated, WTL is the total liquid weight (g), WTAL is the maximum weight (g) of asphaltene in the


Hamouda et al.

Figure 3. Effect of the pressure, temperature, and CO2 on asphaltene precipitation (wt %): (a) model oil (immiscible and miscible processes; dotted ellipse is for the immiscible process at 20 bar and 25 °C and solid ellipse is for the miscible process at 120 bar and 70 °C), (b) model oil (miscible), and (c) crude oil (miscible).

liquid, and WAL is the weight (g) of asphaltene remaining in the liquid phase (effluent) after flooding. The dissolved volume fraction of asphaltene in the liquid and precipitated volume fraction is defined by eqs 3 and 4, respectively

VTL - (WTL - WAL)/FA VFA ) VTL

(3)

WADFo VFD ) 100FA

(4)

where VTL, VFD, and VFA denote the total volume of solution (cm3), volume fraction of precipitated asphaltene (cm3), and volume fraction of the asphaltene in the liquid, respectively. FA and Fo denote the asphaltene and oil densities (g/cm3), respectively. WAD is the weight percent of asphaltene precipitated. The total weight of the liquid (WTL), eq 3, can be rewritten as

WTL ) (VTL - VTLVFA)FA + WAL

(5)

Combining eqs 2 and 5, the weight of precipitated asphaltene [WAD (%)] may be estimated by

WAD (%) )

WTAL - WAL × 100 (VTL - VTLVFA)FA + WAL

(6)

In terms of solubility parameters, the weight of precipitated asphaltene [WAD (%)] is calculated using eq 7

WAD (%) )

(

WTAL - WAL × 100 (7) VA VA 2 VTL - VTL exp - 1 - (δA - δL) FA + WAL VL RT

[

])

where WTAL is the total amount of asphaltene in the liquid (g), WAL is the weight of asphaltene in the liquid phase (g), FA and VTL denote the asphaltene density (g/cm3) and the total volume of solution (cm3), respectively, A and L refer to the asphaltene and liquid phase, respectively, V (cm3/mol) and T (K) represent the molar volume and temperature, respectively, R (MPa cm3 mol-1 K-1) is the gas constant, and δ (MPa1/2) is the Hildebrand solubility parameter. The solubility parameter of the pure asphaltene liquid as a function of the temperature is given by eq 814

δA ) 20.04{1 - 1.07 × 10-3T(C)}

(8)

In this work, the solubility parameter of the liquid eq 9 is based on literature data for different oils and oils used in this study with miscible CO2 flooding. The equation contains fitting parameter (β), which is specified for oils



Figure 4. Effect of the pressure, temperature, and CO2 injection on the amount of asphaltene precipitation (wt %): (a) oil 3 at 150 bar and 373 K, (b) oil 4 at 150 bar and 339 K, (c) oil 5 at 150 bar and 322 K, and (d) oil 6 at 413.69 bar and 344.11 K.

Figure 5. Effect of the initial water saturation on the oil recovery (%) of oil by CO2 flooding at a pressure of 90 bar and temperature of 50 °C: (a) un-normalized recovery and (b) normalized recovery.


Hamouda et al.

δL ) 16.581e-βVCO2/VL

(9)

(cm3/mol)

where VCO2 and VL are the molar volumes of the CO2 and liquid, respectively. β is found to lie between 0.20 and 0.32 for all investigated and available oils in the literature. The used asphaltene density is 1.28 g/mL.35,36 When eq 9 is substituted into eq 7, the following eq 10 is used in this work to predict the weight percent [WAD (%)] of asphaltene precipitation because of the combined effects of temperature, pressure, and CO2:

WAD (%) )

(

WTAL - WAL VA VA VTL - VTL exp - 1 - (δA - (16.581e-βVCO2/VL))2 VL RT

[

× FA + WAL

])

× 100

(10) The Wang and Civian37 solubility model is used. This model predicts the volume fraction of asphaltene precipitated during pressure depletion and as a function of the temperature. In this work, the effect of the temperature and pressure on asphaltene precipitation is estimated using Wang and Civian37

XA ) R1 + R2P + R3P2 + R4P3 + R5T + R6PT + R7P2T + R8T2 + R9PT2 + R10T3 (11) where R1-R10 are constants of the polynomial model. Summary for Estimating the Asphaltene Precipitation by the Model Approach. The experimental mass of asphaltene precipitated is estimated by the difference between the initial and final weight of the dried core at 120 °C under vacuum (-1.5 mbar). On the basis of oil composition, pressure, and temperature, the molar volume of the oil and CO2 are obtained from SRK-Peneloux EOS, using PVTsim version 17. Substituting the estimated molar volumes of the oil and CO2, asphaltene molar volume, and solubility parameter (eq 8) in eq 10 and using the fitting parameter β between 0.2 to 0.32 the best fit of the experimental results of asphaltene precipitation associated with pressure, temperature, and CO2 is obtained. The temperature and pressure effect on the volume fraction of asphaltene precipitation is estimated using the Wang and Civian model (eq 11). The difference between the effect of CO2 may then be compared to the pressure and temperature effect on asphaltene precipitation.

Results and Discussion This section is divided into two parts. The first part deals with asphaltene precipitation associated with pressure, temper-

Figure 6. Comparison between the oil recovery (%) for cores treated with n-decane (reference case), model oil (0.35 wt % asphaltenic oil), and crude oil (containing 10 wt % asphaltenes) as a function of the pressure and temperature.

ature, and CO2 flooding, as well as the verification using literature data. The second part deals with the recovery efficiency because of CO2 flooding. Results of CO2 Flooding Experiments. The experimental asphaltene precipitation results and prediction for model and crude oils are shown in parts a-c of Figure 3. Figure 3a illustrates the effect of the mol % of CO2 in the liquid phase for model oil (for both immiscible and miscible processes) on asphaltene precipitation. It is interesting to note that the amount of asphaltene precipitation increases with an increasing mol % of CO2 in the liquid for the immiscible process, which follows the same trend as in the literature (Figure 4). For the miscible process, asphaltene precipitation increases until CO2 in the liquid reaches above 50 mol % for the flooded cores at 120 bar and 70 °C (marked by an ellipse in Figure 3a), after which the asphaltene precipitation declined. At about 44.4 mol % of CO2 in the liquid, asphaltene precipitation is shown to be about 0.14 wt %. While at 46.2 mol % of CO2 in liquid, asphaltene precipitation increased to 0.17 wt %, after which it decreased to 0.11 wt % at 54.6 mol % of CO2 in liquid. Parts b and c of Figure 3 show the combined effect of the temperature, pressure, and CO2 on asphaltene precipitation for model and crude oils, respectively. At 140 bar and 80 °C, an average asphaltene precipitation of about 0.21 wt % (44.43 mol % of CO2 in liquid) and 9.8 wt % (44.43 mol % of CO2 in liquid) are estimated for the model and crude oils, respectively. While at a pressure of 120 bar and temperature of 70 °C, 0.15 wt % (45.3 mol % of CO2 in liquid) and 8.9 wt % (52.68 mol % of CO2 in liquid) are estimated, respectively. Finally, at 90 bar and 50 °C, 0.08 wt % (47.56 mol % of CO2 in liquid) and 7.0 wt % (51.81 mol % of CO2 in liquid) are estimated, respectively. The experimental error of 6% based on arbitrary selected experiments, in this case at 90 bar and 50 °C, is shown in Figure 3b. The average deviations of the predicted weight percent of asphaltene (wt %) from the experiment using a fitting parameter β of 0.2 may be divided into two parts. The deviation for the miscible CO2 flooding for the model oil (oil 1) and oil 2 is 15%. While deviation for the immiscible CO2 flooding for oil 1 is 40%. The estimated deviations here have the embedded experimental errors. The high deviation in the case of the immiscible flooding may be explained on the basis of the fact that, at low temperatures and pressures (25 °C and 20 bar), a high molar volume ratio (VCO2/VL) lies within the scattered region of the asphaltene precipitation (wt %) in the mapped ternary diagram (literature and this work data; Figure 8) as a function of VCO2/VL and the solubility parameter ratio (liquid/ asphaltene). In other words, this model is recommended in predicting asphaltene precipitation for miscible CO2 flooding. Verification of the Proposed Model Using Literature Data. Parts a-d of Figure 4 compares the predicted and experimental weight percent of that precipitated as a function of moles (%) of CO2 for oil 3 at 150 bar and 373 K,28 oil 4 at 150 bar and 339 K,29 oil 5 at 150 bar and 322 K,22 and oil 6 at 413.69 bar and 353.15 K,30 respectively. The predicted results using eq 10 for literature data are shown in parts a-d of Figure 4. A general average deviation of about 18% using a fitting parameter β of 0.3192 and 0.262 for oils 3-5 and 6, respec(35) Parkash, S.; Moschopedis, S.; Speight, J. G. Fuel 1979, 58, 877– 882. (36) Andersen, S. I.; Speight, J. G. J. Pet. Sci. Eng. 1999, 22, 53–66. (37) Wang, S.; Civian, F. Preventing asphaltene deposition in oil reservoirs by early water injection. Presented at the 2005 SPE Production and Operations Symposium, Oklahoma City, OK, April 16-19, 2005; SPE 94268.


tively, are computed. The deviations for the investigated oil (literature) are within about 22, 19, 17, and 14%, for oils 3-6 (miscible CO2 flooding), respectively. The relative contribution of the experimental pressures and temperatures to asphaltene deposition compared to that for CO2 is presented using the Wang and Civian37 model. The difference between the combined effect and that predicted by Wang and Civian may indicate the effect of the fraction of the CO2 in the fluid on the asphaltene precipitation. The average calculated amount of precipitation because of pressure and temperature for oils 1 and 3-6 for miscible flooding in weight percent are 0.09, 6.72, 0.21, 0.86, and 0.26, respectively. The calculated amount of asphaltene precipitation because of CO2 injection is dependent upon the composition of the liquid, including the fraction of the CO2 in the liquid phase. The asphaltene precipitation increases rapidly when the CO2 fraction in the fluid exceeds a critical point. This observation is in accordance with the literature,8,30 which reported that the amount of asphaltene precipitation because of CO2 injection is dependent upon the concentration of injected CO2 gas in the oil. Some researchers reported the critical injected CO2 concentration: Weyburn reservoir oil (60 mol %)38 and Shengli oil field of China (62.83 mol %).39 In this work, the asphaltene precipitation under miscible flooding is dependent upon the amount of miscible CO2 (mol % of CO2 in the oil) and not the injected amount, as reported in the literature. As shown in Figures 3 and 4, asphaltene began to precipitate as a result of the added effect of CO2 to the effect of temperature and pressure, at about 42, 17, 36, 32, and 36 average mol % of CO2 for oils 1 and 3-6, respectively. It is interesting to note that the mechanism of asphaltene-induced precipitation by CO2 has an average critical content of about 33 mol % of CO2 in the liquid. This may suggest that, below the critical content, the precipitation of asphaltene is caused mainly by the pressure drop and temperature. Because no precipitation occurs below the critical content CO2, one may extrapolate this to the fact that CO2 hinders the effect of the temperature and pressure. In other words, below the critical content of CO2 in liquid, the solubility capacity of oil may increase. Effect of the Initial Water Saturation on Oil Recovery. Figure 5 shows the oil recovery for cores with and without initial water saturation. The cores initially saturated with water (DW, 0.06 M Mg2+, 0.03 M SO42-, or 0.06 M Mg2+ and 0.03 M SO42-) consistently show lower recovery compared to cores with no initial water saturation. It is interesting to see that oil recovery from cores with and without initial water saturation are 48.6% (estimated using total pore volume) and 78.9%, respectively, as shown in Figure 5a. This may be misleading because it is calculated on the basis of the total pore volume rather than the pore volume occupied by oil. Figure 5b shows the oil recovery from cores with a normalized recovery of 62% (estimated from the oil pore volume) for the cores with an initial water saturation. The experimental error of 0.67 and 2.1% based on arbitrary selected experiments, in this case for cores with 0.06 M Mg2+ and 0.03 M SO42- and without initial water saturation, respectively, at 90 bar and 50 °C, is also shown in Figure 5. Effect of the Asphaltene Precipitation on Oil Recovery. Oil recovery under miscible CO2 flooding from cores saturated (38) Srivastava, R. K.; Huang, S. S. Asphaltene deposition during CO2 flooding: A laboratory assessment. Presented at the 1997 SPE Production Operations Symposium, Oklahoma City, OK, March 9-11, 1997; SPE 37468. (39) Yongmao, H.; Zenggui, W.; Yueming, J. B. C.; Xiangjie, L.; Petro, X. Laboratory investigation of CO2 flooding. Presented at the Technical Conference and Exhibition, Abuja, Nigeria, Aug 2-4, 2004; SPE 88883.

Energy & Fuels, Vol. 23, 2009 1125 Table 4. Oil Recovered before Breakthrough and Total Recovered oil used n-decane model oil crude oil

temperature and pressure 80 70 50 80 70 50 80 70 50

°C °C °C °C °C °C °C °C °C

and and and and and and and and and

140 bar 120 bar 90 bar 140 bar 120 bar 90 bar 140 bar 120 bar 90 bar

recovery (%) before BT

total recovery (%)

52.58 47.7 50.11 41.73 42.76 55.4 2.74 13.52 6.11

89 86 81 70.4 75.5 78.92 36.6 36.9 37.6

with different fluids [n-decane (base case), model oil (0.35 wt % asphaltenic oil), and crude oil (containing 10 wt % asphaltenes)] flooded at different temperatures and pressures (50 °C and 90 bar, 70 °C and 120 bar, and 80 °C and 140 bar) are shown in Figure 6. At a temperature of 50 °C and pressure of 90 bar, the displacement efficiencies of about 81, 78.92, and 37.6%, are obtained, respectively, for n-decane, model oil, and heavy crude oil. While at a temperature of 70 °C and pressure of 120 bar, oil recovery increased to about 86% for n-decane, in contrast to model and heavy crude oils, with a reduction to about 75.5 and 36.9%, respectively. At a temperature of 80 °C and pressure of 140 bar, the oil recovery increased to about 89% for n-decane and decreased to about 70.4 and 36.6% for model and heavy crude oils, respectively, as shown (Figure 6). The oil recovery showed an increasing trend as the temperature and pressure are increased from 50 °C and 90 bar to 80 °C and 140 bar for n-decane-saturated cores, which is in contrast to the model and heavy crude oils containing polar components. This may be explained on the basis of possible asphaltene precipitation as the working temperature and pressure is increased, leading to wettability alteration to a more oil-wet condition and/or oil trapping. Miscible CO2 floods showed negligible sensitivity to an increase in temperature and pressure for the crude oil. This may be attributed to a high content of asphaltene (10 wt %) in the crude oil compared to the model oil. Alavian et al.40 reported in their simulation work on fractured reservoirs in the Middle East that CO2 gas injection reduces gas-oil interfacial tension, which significantly impacts the recovery by reducing the capillary retaining forces. ShyehYung41 reported two oil recovery mechanisms, low interfacial tension (IFT) displacement and extraction of oil components, are found to play an important role on miscible and nearmiscible displacements of oil by CO2. Our experiments show that, before CO2 breakthrough (BT), oil production is due to a nearly piston-like displacement mechanism with a higher oil recovery compared to after BT for all of the cases studied, except for the crude oil, as shown in Table 4. Higher oil recovery after breakthrough in the case of n-decane and model oil may be attributed to miscible bank displacement accompanied with interfacial tension reduction, thereby reducing the capillary retaining forces. For the crude oil, lower recovery may be attributed to early breakthrough as a result of channeling. The lighter oil produced after BT, which is observed visually as shown in Figure 7b, may confirm that extraction dominates (40) Alavian, S. S.; Whitson, C. H. International Petroleum Technology Conference (IPTC), 2005; p 10641. (41) Shyeh-Yung, J.-G. J. Mechanisms of miscible oil recovery: Effects of pressure on miscible and near-miscible displacements of oil by carbon dioxide. Presented at the 1991 SPE Annual Conference and Exhibition, Dallas, TX, Oct 6-9, 1991; SPE 22651.


Hamouda et al.

Figure 7. Schematic illustration of (a) possible CO2 miscible displacement behavior, and (b) visual observation demonstrates that the extraction of oil components dominates after CO2 breakthrough.

Figure 8. Mapping of experimental work from the literature and this work for asphaltene precipitation (wt %) in different oils as a function of the solubility parameter ratio (SPR), defined as the solubility parameter of liquid to asphaltene, (liq/asph) and the ratio of the CO2 molar volume to the liquid molar volume (VCO2/VL).

after CO2 breakthrough, which is in agreement with the ShyehYung41 observation. In other words, extraction continues with time until it becomes visual in the recovered oil. It is also interesting to see that mobility control with respect to the rock permeability played an important role in the CO2 flooding process. It is observed, for cores treated with the same oil and flooded at the same temperature and pressure, that the higher displacement efficiencies are higher for cores with lower absolute permeabilities. This may be due to two mechanisms or a combination of the two. The first mechanism may be due to efficient divergence of the CO2 flow path for the low permeable rocks. The second mechanism may be related to the large surface area exposed to the flowing CO2, hence efficient extraction of lighter components, as illustrated by the schematic drawing in Figure 7a. A ternary diagram is constructed to present the dependence of asphaltene precipitation upon the solubility parameter of the fluid and the fractional molar volume of CO2 in the fluid. It gives an approximation to predict possible asphaltene precipitation. The molar volume ratio (VCO2/VL) depends upon the fluid composition, temperature, and pressure and, hence, includes the changes in the fluid properties as conditions

change. The ternary diagram is shown in Figure 8. The figure is a mapped miscible CO2 flooding work for different oils by different researchers and at different conditions, including the work performed here. The ternary diagram may be divided into two main areas: one with a maximum wt % asphaltene precipitation of χ 0.2 wt % and the other area for >0.2 wt %, which may almost be presented by a straight line, with an approximate SPR between 0.1 and 0.2. It is interesting to observe that the high molar volume ratio (VCO2/VL) lies within a scattered region of the asphaltene precipitation (wt %), associated with the variation of the SPR. In other words, SPR seems to be the determining factor for the asphaltene deposition, which is not unreasonable because it is influenced by the molar volume ratio. The high deviation from the prediction may, then, be expected to be within this region of the ternary diagram, with a large variation of the SPR. Conclusions A modified Hirschberg et al. model is developed to account for the effect of CO2 on asphaltene precipitation. The model takes into account the molar volume ratio of CO2 and fluid as a function of the solubility parameter of the fluid. The model fits the literature data within an average deviation of 18%. An average deviation of about 40% for the case of the immiscible CO2 flooding compared to 15% deviation in case of miscible CO2 flooding in this work is observed. The obtained deviation of the 40% case may be due to the high molar volume ratio (VCO2/VL) for the used model oil, which lies within the scattered region of the asphaltene precipitation (wt %) in the mapped ternary diagram with large variations in the SPR, causing the obtained large deviation from the prediction. Below a critical CO2 fraction (mol %) in fluid, asphaltene is stabilized, which otherwise would precipitate based on the predicted and experimental asphaltene solubility behavior with the temperature and pressure. The identified average, highest, and lowest critical points for CO2 expressed as mol %, reported in the literature and from this work, are 33, 42, and 17, respectively. The reported critical CO2 is based on the fraction of CO2 in the liquid phase. This is an important point to be taken into account at the early stage of EOR when planning for CO2 injection.


The miscible flood showed sensitivity to initial water saturation. Average displacement efficiency for cores with and without initial water saturation are about 48.6 or 62% (normalized DE) and 78.9%, respectively. This may suggest that CO2 dissolution in water could reduce the available CO2 for the miscibility flooding, especially for the small-scale flooding with CO2. Acknowledgment. The authors thank the University of Stavanger for the financial support of this project. We acknowledge Krzysztof piotr Dziadosz and Mehmed Nazecic for their assistance in the experimental setup and Unni Hakli for her positive support and help in getting the chemicals needed.

Nomenclature M ) molar mass (g/mol) P ) pressure (MPa) R ) gas constant (MPa cm3 mol-1 K-1) T ) temperature (K) V ) molar volume (cm3/mol) W ) weight X ) volume fraction

Energy & Fuels, Vol. 23, 2009 1127 Greek Letters δ ) solubility parameter (MPa)0.5 F ) density (kg/m3) φ ) volume fraction β ) fitting parameter R ) polynomial constant χ ) estimated maximum wt % asphaltene precipitation within the scattered region of the mapped ternary diagram Subscripts A ) asphaltene AD ) asphaltene deposited AL ) asphaltene in the liquid L ) liquid FA ) fraction of asphaltene in the liquid FD ) fraction of asphaltene deposited TAL ) total asphaltene in the liquid Supporting Information Available: Data used for the proposed model. This material is available free of charge via the Internet at http://pubs.acs.org. EF800894M

Investigating the Effect of CO2 Flooding on Asphaltenic Oil Recovery

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