Energy Fuels 2010, 24, 3655–3660 Published on Web 05/25/2010
: DOI:10.1021/ef100266p
Laboratory Study of Alkyl Ether Sulfonates for Improved Oil Recovery in High-Salinity Carbonate Reservoirs: A Case Study Mohamed Aoudia,*,† Rashid S. Al-Maamari,‡ Moein Nabipour,§ Ali S. Al-Bemani,‡ and Shahab Ayatollahi§ †
Department of Chemistry, College of Science, Sultan Qaboos University, Post Office Box 36, Al-Khodh 123, Sulanate of Oman, ‡ Department of Petroleum and Chemical Engineering, Sultan Qaboos University, Post Office Box, 33, Al-Khodh 123, Sultanate of Oman, and §School of Engineering, Shiraz University, Shiraz, Iran Received March 8, 2010. Revised Manuscript Received April 26, 2010
Yibal oil reservoir, a fractured carbonate formation located in the north of Oman and characterized by high salinity brine and high temperatures, is a potential candidate for enhanced oil recovery (EOR) projects. This experimental study focused on the possibility to use surfactant injection as an EOR process in the Yiabl field. On the basis of the results from our previous investigations, ethoxylated sulfonates and amphoteric surfactants were used in this study. Selected surfactants showed a great tolerance to high salinity and temperatures. All surfactant systems displayed dynamic interfacial tension (IFT) behavior, in which transient ultra-low IFTs were detected. Dilute surfactant solutions (0.1 wt %) were considered for core-flooding tests on limestone plugs. In one set of experiments, surfactant solutions were injected into a fully water-flooded core (surfactant tertiary recovery). In another set, surfactant solutions were injected without pre-water-flooding (surfactant-modified water-flooding or surfactant secondary recovery). Results of tertiary recovery were found to be between 1 and 7% of original oil in place (OOIP), which correspond to 6 and 24% of residual oil in place (percentage based on the remaining oil in place after water-flooding). Tertiary surfactant injection therefore appears to be an attractive option for pre-water-flooded zones for additional oil recovery. In the other hand, results of secondary recovery for some surfactants showed significant oil recovery compared to water-flooding, whereas for other surfactants, water-flooding was more effective. Secondary surfactant recovery resulted in faster rate recovery as compared to water-flooding. Thus, minimum pore volume (PV) injected at ultimate oil recovery for 7-58 surfactant was found to be significantly lower (2.3 PV) than the corresponding PV in water-flooding (9.1 PV). by the surfactant of the reservoir rock.7-11 Both mechanisms have been shown to be responsible for the increase in oil recovery. Recently, a laboratory feasibility study of dilute surfactant injection for the Yibal field (Oman) was reported by Babadagli et al.12 as an alternative to the current water-flooding scheme in the Yibal field (chalky formation). The authors used a series of conventional cationic, anionic, and non-ionic surfactants. Core-flooding experiments were conducted, and the results were evaluated in terms of the final oil recovery. Surfactant type, concentration, and therefore, IFT were shown to be the main factors in choosing the proper surfactant for tertiary oil recovery (water-flooding followed by surfactant injection). However, the experiments were carried out at room temperature using synthetic brine solution (3% NaCl) as the water phase. These conditions (temperature and brine) are largely different from the drastic conditions prevailing in the reservoir. The Yibal field, the largest oilfield in the Sultanate of Oman (15% of the oil production in the country) consists of carbonate mud. Porosity ranges from 30 to 35%. Permeability ranges from 1 to 200 mD, with the average matrix permeability of 10 mD. The oil is relatively light (F=0.836 g/cm3 at 65 °C), and its viscosity is less than 1 cP in reservoir conditions. The reservoir temperature shows a gradient from 70 to 80 °C. Currently, the field is undergoing water-flooding; the water production steadily increased during oil production to a more than 98% water cut. The
Introduction Surfactant-based chemical-flooding processes have been intensively studied, and many research papers have been published.1-4 These studies focused on two inter-related mechanisms for enhanced oil recovery (EOR): (i) the ability of the surfactant to produce ultra-low interfacial tension (IFT) between brine and residual oil5,6 and (ii) the wettability alteration *To whom correspondence should be addressed: College of Science, Sultan Qaboos University, P.O. Box 36, Al-Khodh 123, Sultanate of Oman. E-mail:
[email protected]. (1) Spinler, E. A.; Baldwin, B. A. In Surfactant Fundamentals and Application in the Petroleum Industry; Schramm, L. L., Ed.; Cambridge University Press: New York, 2000; pp 159-202. (2) Hou, J. R.; Liu, Z. C.; Dong, M. Z.; Yue, X. A.; Yang, J. Z. J. Can. Pet. Technol. 2006, 45 (11), 27. (3) Liu, Q.; Dong, M.; Yue, X.; Hou, J. Colloids Surf., A 2006, 273, 219. (4) Zhang, Y. P.; Huang, S.; Dong, M. J. Can. Pet. Technol. 2004, 44 (2), 42. (5) Bahar, N.; Shiea, M.; Gholipoor, M.; Nabipour, M.; Aoudia, M.; Ayatollahi, Sh. Effect of slugs arrangement injection during chemical flooding in vuggy rocks. Proceedings of the 1st International Conference of European Association of Geoscientists and Engineers (EAGE), Shiraz, Iran, May 4-6, 2009. (6) Aoudia, M.; Al-Maamari, R. S.; Nabipoor, M.; Al-Bemani, A. S.; Ayatollahi, S. Novel alkyl ether sulfonates for improved oil recovery from Yibal field (Oman). Proceedings of the 14th European Symposium on Improved Oil Recovery (IOR), Cairo, Egypt, April 22-24, 2007. (7) Seiedi, O.; Rahbar, M.; Nabipour, M.; Ayatollahi, S.; Ghatei, M. Monitoring the wettability of oil reservoir rocks by AFM during surfactant treatment. Proceedings of the International Conference of European Association of Geoscientists and Engineers (EAGE), Shiraz, Iran, May 4-6, 2009. (8) Seiedi, O.; Nabipour, M.; Mogharebian, S.; Bahar, N.; Ayatollahi, Sh.; Ghatei, M. H. Macroscopic, microscopic investigation of wettability alteration of Iranian oil field rock using surfactants. Proceedings of the 10th International Symposium on Evaluation of Wettability and Its Effect on Oil Recovery, Abu Dhabi, United Arab Emirates, Oct 26-28, 2008. r 2010 American Chemical Society
(9) Babadagli, T. J. Colloid Interface Sci. 2002, 246 (1), 203. (10) Standnes, D. C.; Austad, T. J. Pet. Sci. Eng 2003, 39, 431. (11) Standnes, D. C.; Austad, T. Colloids Surf., A 2003, 216, 243. (12) Babadagli, T.; Al-Bemani, S. A.; Boukadi, F.; Al-Maamari, R. S. J. Pet. Sci. Eng. 2005, 48, 37.
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Table 1. Water Composition for the Yibal Reservoir (All Results in g/ L, except for Conductivity in mS cm-1) pH conductivity bicarbonate carbonate sodium potassium calcium magnesium chloride sulfate total
Table 2. Molecular Structure of the Different Surfactants Used in This Study
6.94 432 0.089
AES-128 AES-208 AES-218 AES-506 7-58
53.98 0.74 16.21 5.01 135.62 0.074 200.23
a
R1
R2
x
percent activity
tallow amine nonylphenol nonylphenol iso-tridecyla iso-tridecylb
C14/16 C14/16 C10 C14/16 C14/16
8 (EO) 8 (EO) 8 (PO) 6 (EO) 6 (EO)
30 50 50 50 50
From propylene tetramer. b From butylene trimer.
Table 3. Core Properties, Surfactant Type, and Recovery Process for Each Core
formation brine composition reflects extremely high reservoir salinity (∼200 g/L) as well as a relatively high concentration of divalent ions (Ca2þ and Mg2þ). Thus, the use of a synthetic brine solution (3% NaCl) may be somehow misleading when one considers the IFT as a main factor in choosing the proper surfactant for optimum additional recovery, owing to the fact that the formation water in a real petroleum reservoir contains numerous other ions (notably Ca2þ and Mg2þ). In this context, the presence of Ca2þ and/or Mg2þ was indeed shown to result in a drastic increase of the IFT.13 Furthermore, temperatures in many oil reservoirs are relatively high (70-130 °C), thereby the effect of the temperature on the thermal stability of the surfactants, the oil/water IFT, and the adsorption of the surfactant on the solid matrix must also be taken into account by carrying out IFT and core-flooding measurements at the reservoir temperature. Accordingly, we recently addressed14 this crucial issue of surfactant-brine (Yibal) compatibility for a series of novel surfactants (alkyl ether sulfonates and amphoteric) at 60 °C, as well as their efficiency in reducing the IFT between Yibal crude oil and surfactant solution in reservoir conditions (salinity and temperature). All surfactants showed excellent properties required for use in EOR applications, namely, (i) compatibility with reservoir conditions (salinity and temperature) and (ii) ultra-low oil/water IFTs. At this juncture, it is worthy to note that alkaline and/or polymers are often added to surfactants in EOR methods based on chemical-flooding.2,3,15 In this paper, our aim is to demonstrate that, in addition to their excellent tolerance to high salinity and temperature, these ethoxylated sulfonate and amphoteric surfactants would produce additional oil when used as secondary recovery (injection in an untouched/unflooded part of the reservoir) or tertiary recovery (injection in a water-flooded reservoir). This scheme is justified by the fact that some parts of the reservoir were totally depleted by water injection, while others are still untouched.
pore core porosity permeabiliy volume number (%) (mD) (cc) 4 5 6 7 8 9 10 11 12 13 14 16
13.8 13.9 14.6 13.7 14.1 13.7 14.5 14.4 13.6 14.1 14.6 13.8
2.3 2.2 2.5 2.3 2.3 2.2 2.2 2.3 2.1 2.3 2.2 2.9
11.8 12.1 12.7 11.6 11.5 11.3 12.9 12.7 11.8 12.3 12.6 11.8
Swir 0.32 0.27 0.30 0.29 0.33 0.28 0.29 0.27 0.31 0.29 0.25 0.32
surfactant type, 0.1% recovery (w/w) process 7-58 7-58 AES-208 AES-208 6-105 6-105 AES-128 AES-128 AES-506 AES-506 AES-218 AES-218
secondary tertiary tertiary secondary secondary tertiary secondary tertiary secondary tertiary secondary tertiary
Surfactants used in this work (ethoxylated sulfonates and amphoteric surfactants) were kindly supplied by Oil Chem Technologies, Inc. (Sugar Land, TX) and used as received. The ethoxylated sulfonates have the following general molecular structure:
Complete description of the ethoxtylated sulfonates and amphoteric surfactants is given in Table 2. The amphoteric surfactant used is 6-105, which is a 30% active solution of a proprietary amphoteric surfactant. Surfactant activity is defined as the mass (in grams) of pure surfactant in 100 g of commercial surfactant sample. All surfactant solutions were made with Yibal brine. Indiana limestone (Tetra Tech, Inc., Salt Lake City, UT) was used to mimic a homogeneous, similar core of the Yibal field. Core plugs used were approximately 1.5 in. in diameter and 3 in. in length, and their properties are given in Table 3. Core cleaning was conducted by methanol in a Soxhlet device for 2 days, and the drying stage was performed at 75 °C (Yibal average reservoir temperature). IFT Measurements. Different techniques used to measure surface and IFT have been described recently.16 In this work, IFT measurements were carried out with a spinning drop tensiometer (model 500, University of Texas at Austin, Austin, TX). The IFT (γ) was calculated from Vonnegut approximation (infinite oil drop length limit):
Experimental Section The study basically addressed measurements of IFT before selection of different percentages, conduction of water, and then surfactant-flooding or surfactant-flooding from the start. Materials. Yibal crude oil and brine were provided by Petroleum Development Oman. The brine was filtered (Whatman No. 42 paper filter) prior to use in the flooding tests. The oil was centrifuged and filtered to reduce water content. Yibal brine composition is shown in Table 1.
γ ¼ 0:521ðD3 =P2 ÞΔF where P, D, and ΔF are the period, drop diameter, and the difference in density between crude oil and brine, respectively. A complete description of the procedure is given elsewhere.14 Core-Flooding. Core-flooding experiments were carried out at the Yibal average reservoir temperature (75 °C) and constant
(13) Jennings, H. T.; Johnson, J. E.; McAuiliffe, C. D. J. Pet. Technol. 1974, 26, 1344. (14) Aoudia, M.; Al-Shibli, M. N.; Al-Kamisi, L. H.; Al-Maamari, R.; Al-Bemani, A. J. Surfactants Deterg. 2006, 9 (3), 287. (15) Lucas, E. F.; Mansur, C. R.; Spinelli, Li.; Queiros, J. G. C. Pure Appl. Chem. 2009, 81, 473.
(16) Kopczynska, A.; Ehreinstein, G. W. J. Mater. Educ. 2007, 29, 325.
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Aoudia et al. Table 4. Transient Minimum and Equilibrium IFTs between Crude Oil and Reservoir Water at 75 °C for the Surfactants surfactant
transient minimum γ (mN m-1)
equilibrium γ (mN m-1)
7-58 6-105 AES-128 AES-208 AES-218 AES-506
0.0052 0.0055 0.0018 0.018 0.0550 0.0049
0.023 0.054 0.024 0.048 0.184 0.075
Figure 1. Variation of the IFT between crude oil and formation water with time for 7-58 surfactant (0.1%) at T = 70 °C.
volumetric flow rate of 0.4 mL/min. The core plugs were saturated with brine (1 day) in high vacuum followed by the injection of additional three pore volumes (PVs). A total of 10 PVs of dead Yibal oil were injected to establish irreducible water saturation (Swir). Core samples were subjected to water/surfactant-flooding without aging in oil. In this study, two sets of experiments were used. In the first set, water-flooding was followed by surfactant-flooding (surfactant tertiary injection). For this purpose, 10 PVs of brine were injected and the rate and ultimate oil recovery by water-flooding (brine injection without surfactant) was measured for selected cores. Next, 10 PVs of surfactant solution (0.1%) were injected to evaluate the surfactant-flooding efficiency (rate and ultimate recovery) after water-flooding. In the second set, 10 PVs of surfactant solutions were injected into an oil-saturated core sample (modified waterflooding or surfactant secondary recovery).
Figure 2. Variation of the IFT between crude oil and formation water with the temperature for 7-58 surfactant (0.1%).
minima (γmin) and equilibrium values (γeq), as compiled in Table 4. According to this table, transient ultra-low IFT against crude oil fall in the range from 1.8 10-3 to 5 10-2 mN m-1 and are achieved after about 25 min in the spinning drop tensiometer. The equilibrium values were in the range from 7.5 10-2 to 1.8 10-1 mN m-1. Dynamic IFTs have been reported in a number of surfactant-oil systems,17-20 in which the transient ultra-low minimum IFT was believed to occur when the adsorbed surfaceactive species including the added surfactant and the crude-oilactive species reach the optimum concentration and ratio. Yibal crude oil is relatively acidic and is characterized by a total acid number of 0.25 mg of KOH/g of oil, thereby making the above suggestion for the occurrence of the ullra-low IFT quite plausible. Furthermore, Taylor and Schram20 demonstrated the practical importance of this transient minimum in terms of EOR by suggesting that oil recovered through surfactantenhanced alkaline-flooding of Berea sandstone cores correlates better with initial IFT than with the equilibrium IFT. The effect of the temperature on the IFT between Yibal crude oil and brine in the temperature range of 60-80 °C was also investigated (Figure 2). This is of significant importance in actual EOR processes using surfactant-flooding because the temperature in many reservoirs is not uniform. For instance, the temperature in the Yibal field ranges between 70 and 80 °C, and consequently, a change of the IFT may occur during
Results and Discussion There are different ways to present the results obtained in this study. As the title of the paper indicates, it was chosen to present the IFT and the core-flooding behaviors. The secondary and tertiary concepts of water- and surfactant-flooding were addressed whether carried out with water- and then surfactant-flooding (surfactant tertiary) or starting with modified water-flooding tertiary from day 1. IFT Behavior. IFT between Yibal crude oil and brine was conducted for the different surfactants at the average reservoir temperature (75 °C). For 7-58 (0.1%), the IFT was measured at different temperatures in the range of 60-80 °C. Dynamic IFTs were observed for all surfactants, and a representative IFT versus time plot is depicted in Figure 1 for a typical surfactant (7-58 at 0.1% and T=70 °C). This observed dynamic IFT behavior is similar to that reported in our earlier study carried out at 65 °C.14 The IFT first decreases very rapidly from an oil-brine IFT value of γRC =12 mN m-1 (IFT between crude oil and formation water in reservoir conditions and in the absence of surfactant) to a transient ultra-low IFT (γmin ∼5.210-3 mN m-1), followed by a gradual increase to an equilibrium value (γeq ∼ 2.3 10-2 mN m-1). The variation of the IFT was monitored up to a 24 h period, during which the IFT was found to remain practically constant. The observed transient ultra-low IFT occurs at ∼12 min. Similar IFT versus time curves were obtained for all other surfactants and transient ultra-low IFT
(17) Zhao, Z.; Liu, F.; Qiao, W.; Cheng, L. Pet. Sci. Technol. 2006, 24, 1469. (18) Zhao, Z.; Li, Z.; Qiao, W.; Cheng, L. Colloids Surf., A 2005, 259, 71. (19) Clint, J. H.; Neustadter, E. I.; Wheeler, P. A. Colloids Surf. 1984, 11, 129. (20) Taylor, K. C.; Schram, L. L. Colloids Surf. 1990, 47, 245.
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Figure 3. Oil recovery for water-flooding followed by (O) tertiary surfactant injection and (b) secondary surfactant injection for 7-58 (0.1%) surfactant.
Figure 4. Oil recovery for water-flooding followed by (O) tertiary surfactant injection and (b) secondary surfactant injection for AES-128 (0.1%) surfactant.
reservoir flooding. Figure 2 shows a slight increase in the transient IFT minima (γmin), concomitant with a relatively more pronounced increase in the IFT at equilibrium (γeq). However, both IFTs remained relatively low (γmin = 1.1 10-3 - 2.1 10-2 mN m-1, and γeq = 1.17 10-2 - 1.1 10-1 mN m-1). This indicates that, with respect to the temperature variation, these surfactants show a flexible range of applicability, in which the low IFT regime is maintained as highly desired in actual reservoir flooding. Core-Flooding. Two sets of experiments were conducted in this investigation. In the first set, water-flooding was followed by the injection of a surfactant aqueous solution (0.1%) to assess the efficiency of surfactant tertiary recovery in the Yibal field. In the second set of experiments, the aqueous surfactant solution was injected into the oil-saturated (virgin) core samples. This test was aimed to evaluate the efficiency of surfactant secondary recovery. Surfactant Injection after Water-Flooding (Surfactant Tertiary Recovery). Oil recoveries versus PVs injected were measured, and two typical plots are shown in Figures 3 and 4. The ultimate recoveries are plotted altogether in Figure 5. As indicated in this figure, in all cases, an additional increase in oil recoveries between 1 and 7% of original oil in place (OOIP) was achieved. Highest additional oil recoveries were generated with 7-58 (7%), AES-506 (6%), AES-208 (7%), and 6-105 (4%) surfactants, whereas relatively lower additional oil recoveries were obtained with AES-218 (1%) and AES-128 (1%) surfactants. Inspection of Table 4 and Figure 5 reveals that higher transient minimum IFT (γmin = 5.5 10-2 mN m-1) and equilibrium IFT (γeq = 1.8 10-1 mN m-1) are found for the surfactant-type AES-218. Interestingly, the lowest additional oil recovery was also observed with this surfactant. This seems to suggest that the reduction of capillary forces through the lowering of the IFT may be indeed an important factor in this particular surfactant-brine-oil system. On the other hand, it is also remarkable from Table 4 and Figure 5 that lower transient IFT does not necessarily yield higher oil recovery. Thus, the AES-128 surfactant system (γmin =1.8 10-3 mN m-1) resulted in lower additional oil recovery (1% of OOIP) than the AES-208 surfactant system (7% of OOIP), for which γmin=1.8 10-2 mN m-1, indicating that reducing the residual oil saturation cannot always be achieved only through reduction
Figure 5. Performance of oil recovery by water-flooding, tertiary surfactant-flooding, and secondary water-flooding.
of the capillary forces and that other mechanisms may also play a determinant role in oil recovery efficiency. For instance, surfactant losses because of adsorption on the rock surface certainly weaken the effectiveness of the injected chemical flood in reducing oil-water IFT. IFT values reported in Table 4 were measured in the absence of fluid-rock interactions and, therefore, may not reflect the actual situation in core-flooding experiments, where the surfactant is in continuous contact with carbonate. Accordingly, the observed differences in oil recovery efficiencies for the series of surfactants tested may be attributed to differences in their relative adsorption on the carbonate core, which in turn may induce different wettability alterations at the solid surface. Wettability changes by surfactants were indeed shown to be a key mechanism in additional oil recovery, as evidenced from the intensive literature published in this important area.21-23 At this juncture, it is worthy to mention that the pH of Yibal formation water is 6.8, well below the (21) Zhang, D. L.; Liu, S.; Puerto, M.; Miller, C. A.; Hirasaki, J. J. Pet. Sci. Eng. 2006, 52, 213. (22) Razaei Gomari, K. A.; Hamouda, A. A. J. Pet. Sci. Eng. 2006, 50, 140. (23) Somasdundaran, P.; Zhang, L. J. Pet. Sci. Eng. 2006, 52, 198.
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(AES-208, AES-218, and AES-128). Average recoveries of water-flooding and surfactant injection were found to be 78 and 69% of OOIP, respectively. Using these surfactants in secondary recovery cannot therefore be recommended as an efficient process in terms of both cost and recovery. On the contrary, the addition of 7-58, AES-506, and 6-105 surfactants to water resulted in higher recovery than water-flooding. Oil recoveries generated were 83% (7-58), 82% (AES506), and 89% (6-105) of OOIP and represent an additional increase in oil recovery of 13% (7-58), 11% (AES-506), and 6% (6-105) over water-flooding. In terms of average recoveries, water- and surfactant-flooding resulted in 75 and 85% recovery of OOIP, respectively. Thus, with this group of surfactants, starting the project with the surfactant injection (modified water-flooding) appears to be more effective as long as the economic viability of the process is established. This is a crucial issue in timing a given surfactant flood for an oilfield. EOR practices are generally sought for more residual oil recovery after secondary recovery. However, using surfactant-modified water flood as a secondary recovery may generate more additional oil recovery than the overall oil recovery cumulated by water-flooding followed by surfactant-flooding. Another performance indicator in flooding efficiency is the recovery rate. Figure 5 shows that these rates for 7-58 (2.3 PV), AES-506 (6.2 PV), and 6-105 (6.5 PV) surfactants are lower than the corresponding ones in unmodified waterflooding (average of 9.1 PV). An interesting feature is also the relative difference in the recovery rate for the different surfactants. A relatively low value of PV of injected brine (2.3 PV) is needed to recover almost the same amount of oil for 7-58 surfactant compared to 6.2 PV for AES-506 and 6.5 PV for 6-105. Therefore, although the three surfactants yielded similar substantial oil recoveries, the surfactant 7-58 is by far the most efficient one to be used in actual reservoir flooding. The economics of the recovery by surfactant injection is often critical because of the slow rate of recovery, even though high ultimate recovery can be generated. Of practical interest is also the comparison between the flooding efficiency of surfactant secondary recovery and surfactant tertiary recovery. Again, two different behaviors were observed. Surfactant secondary injection generated higher additional oil recoveries of 83% (7-58), 82% (AES506), and 89% (6-105), as compared to the corresponding additional recoveries of 77% (7-58), 77% (AES-506), and 87% (6-105) generated by tertiary surfactant injection. On the other hand, surfactant tertiary injection generated more additional oil recoveries of 81% (AES-208), 79% (AES-218), and 83% (AES-128) than the corresponding additional oil recoveries of 71% (AES-208), 71% (AES-218), and 66% (AES-128) generated by modified water-flooding. The choice between the two processes is, therefore, dependent upon the type of surfactant used. On the basis of the above observations, it appears that oil recovery is clearly dependent upon the surfactant structure, as reflected by the similar oil recovery achieved with 7-58 and AES-506 (Figure 5), owing to the fact that these two surfactants have similar molecular structures (Table 2). Both are branched alkyl ether sulfonates with the two hydrophobic chains consisting of an iso-tridecyl group (R1) and a C14-C16 group (R2), whereas the hydrophilic polyoxyethylene portion contains six oxyethylene groups (-CH2CH2O-). The slight difference is that R1 consists of propylene tetramer (AES-506) or butylene trimer (7-58). According to our
Figure 6. Comparison of the tertiary recovery performance based on OOIP before and after water-flooding.
point zero charge (pzc) of carbonate, and consequently, one would expect a significant adsorption of the anionic alkyl ether sulfonates onto the overall positively charged carbonate. Future work will focus on this important issue. Additional oil recoveries estimated above when the surfactant is used as a tertiary agent were based on OOIP before water-flooding. To truly quantify the ultimate oil recovery by tertiary surfactant-flooding, one should consider the recovery based on oil in place remaining after water-flooding. Such ultimate oil recoveries were estimated and are shown in Figure 6, along with the ultimate recoveries based on the OOIP before water-flooding. Significant recoveries between 17 and 24% are obtained with five surfactants (7-58, AES-506, 6-105, AES-208, and AES 218), whereas relatively lower oil but still appreciable recovery is achieved with AES128 surfactant (6%). These surfactants can therefore be potential candidates for EOR application in the Yibal oilfield, and surfactant injection is recommendable in the prewater-flooded zones as long as the proper surfactant type is selected and the process can be economically viable. Surfactant Secondary Recovery (Modified Water-Flooding). Surfactant secondary oil recovery (modified waterflooding) was also conducted to investigate the effect of surfactant-flooding on the untouched part of the reservoir during the water-flooding process. Oil recoveries (percentage of OOIP) were measured, and two different behaviors were observed. For one set of surfactants (7-58, AES-506, and 6-105), the oil recovered by modified water-flooding was higher than that obtained by water-flooding alone. On the other hand, an opposite trend was observed with the remaining surfactants tested (AES-128, AES-208, and AES-218). Two typical plots for oil recovery versus PV fluid injected are shown in Figures 3 and 4. From such plots, one can evaluate the flooding efficiency of the process in terms of minimum PV required to reach ultimate recovery (rate of recovery) and the magnitude of this ultimate recovery. To compare the modified (surfactant added) and unmodified (water only) flooding results, the ultimate recoveries are plotted altogether in Figure 5. Also mentioned in this Figure 5 (between parentheses) are rates of recoveries. Clearly, the addition of surfactant into water did not generate more oil recovery over water-flooding for three surfactant systems 3659
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results, this particular structure appears to generate high additional recovery (Figure 5).
7-58, AES-506, and 6-105 surfactants, namely, an average of 85% recovery of OOIP, whereas the corresponding unmodified water injection yielded an average recovery of only 75% of OOIP. This indicates that surfactant injection (modified water-flooding) can be an attractive alternative to increase oil recovery from the untouched unfractured zones of the reservoir, given that a suitable surfactant is used. Our results showed that low IFT does not necessarily correlate with higher oil recoveries, indicating that IFT is not probably the unique mechanism in oil recovery enhancement. The probable adsorption-related IFT behavior of anionic surfactants onto positively charged carbonate may also influence the oil recovery efficiency. For some surfactants, modified (secondary) water-flooding by surfactants resulted in faster rate recovery, as compared to unmodified water-flooding (no surfactant injection). Thus, minimum PV at ultimate oil recovery for 7-58 was found to be significantly lower (2.3 PV) that the corresponding PV in unmodified water-flooding (9.1 PV). The Yibal field has been submitted to extensive waterflooding for many years, and surface facilities have been designed to recycle produced water as injection water. Compatibility of these novel surfactants with reservoir brine therefore allows the use of produced formation water as chemical solution makeup water and makes the process cost-effective.
Conclusions Dynamic IFTs between Yibal oil and brine were observed at the average reservoir temperature (75 °C). In all oil-brinesurfactant systems, the IFT decreases very rapidly to a transient minimum value (10-2 - 10-3 mN m-1), followed by a gradual increase to an equilibrium value (∼10-2 mN m-1). This dynamic IFT behavior was associated with the acidic nature of Yibal crude oil. The effect of the temperature on the variation of the transient minimum and the equilibrium IFTs for a representative surfactant (7-58) showed the ability of the surfactant to generate a wide range of applicability, in which the IFT remains relatively low (∼10-2 - 10-3 mN m-1) as highly desired in actual EOR processes. Core-flooding results were evaluated in terms of the ultimate oil recovery. Injection of the surfactant into a fully water-flooded core (surfactant tertiary recovery) resulted in an additional recovery between 1 and 7% of OOIP or between 6 and 24% of remaining oil after water-flooding. Tertiary surfactant injection therefore appears to be an attractive option for pre-water-flooded zones for additional recovery, as long as the appropriate surfactant is selected. Surfactant injections without pre-water-flooding (surfactant secondary recovery) showed two different behaviors. For one set of surfactants (AES-208, AES-218, and AES-128), the average oil recovery was found to be 69% of OOIP, whereas unmodified water injection yielded a relatively higher average recovery of 78% of OOIP. An opposite trend was observed for
Acknowledgment. We are very grateful to Sultan Qaboos University (SQU) for financially supporting this work through a HM strategic research grant. We express our thanks to Mr. Nayyar Afzal (SQU) for the assistance during the laboratory core-flooding measurements.
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