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Improved oil recovery by adsorption–desorption in chemical flooding
Journal of Petroleum Science and Engineering 43 (2004) 75 – 86 www.elsevier.com/locate/petrol
Improved oil recovery by adsorption–desorption in chemical flooding Q. Liu a, M. Dong a,*, W. Zhou a, M. Ayub a, Y.P. Zhang b, S. Huang b b
a Faculty of Engineering, University of Regina, Regina, SK, Canada S4S 0A2 Saskatchewan Research Council, 6 Research Drive, Regina, SK, Canada S4S 3Y9
Received 10 April 2003; accepted 18 December 2003
Abstract Surfactant loss is one of the major concerns with chemical oil recovery processes in which surfactant is one of the components of the chemical formula. Surfactant loss due to adsorption on the reservoir rocks weakens the effectiveness of the injected chemical slug in reducing oil – water interfacial tension (IFT) and makes the process uneconomical. Adsorption-related interfacial tension behavior and its effect on oil recovery has not been understood completely. This paper reports the investigation of oil – water IFT behavior when the chromatographic separation of the surfactant mixture occurs during surfactant/alkaline corefloods. In this work, surfactant and alkaline concentrations in the effluent of corefloods and oil – water interfacial tension were determined under different injection strategies. It was found that, in an extended waterflood following an alkaline-surfactant slug injection, surfactant desorbed into the water phase. This desorption of surfactant lasted for a long period of the waterflood. Although the concentration of the desorbed surfactant in the extended waterflood was very low, an ultra-low oil – water IFT was obtained by using a suitable alkaline concentration. Coreflood results showed that an additional 13% of the initial oil in place (IOIP) was recovered after the alkaline – surfactant injection by the synergism of the desorbed surfactant and alkaline. This result indicates that the efficiency and economics of a chemical flood could be improved by utilizing the desorbed surfactant during extended waterflood processes. D 2004 Published by Elsevier B.V. Keywords: Adsorption; Desorption; Surfactant; Interfacial tension; Chemical flood; Enhanced oil recovery; Coreflood
1. Introduction In order to mobilize residual oil trapped by capillary forces in oil reservoirs, many enhanced oil recovery (EOR) methods rely on reducing the oil – water interfacial tension (IFT) to extremely low values, often to 10 2 dyn/cm or less (Morgan et al., * Corresponding author. Tel.: +1-306-337-2269; fax: +1-306585-4485. E-mail address: [email protected] (M. Dong). 0920-4105/$ - see front matter D 2004 Published by Elsevier B.V. doi:10.1016/j.petrol.2003.12.017
1979). Examples of improved oil recovery processes utilizing surfactants include micellar polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline surfactant foam flooding (Berger and Lee, 2002). Surfactant reduces the IFT between the brine and residual oil and therefore increases the capillary number. The capillary number, Nc, is used to express the ratio of viscous forces to capillary forces acting on entrapped oil drops within porous media. A capillary number of about 10 6 is found after a typical waterflood, and this number can be increased by two or
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three orders of magnitude when the IFT is reduced from about 20 –30 to 10 2 dyne/cm. In chemical flooding, surfactants are inevitably adsorbed on the surface of reservoir rock by the rock – oil –brine interaction. Surfactant adsorption is one of the important factors governing the economic feasibility of chemical flooding processes (Gale and Sandvik, 1973). Zaitoun et al. (2003) studied the adsorption of a surfactant in brine with high salinity and high concentration of divalent ions. Their experimental results showed that the adsorption of a surfactant (primary surfactant) could be reduced significantly by the use of another surfactant that acted as an anti-adsorption additive. Trogus et al. (1977) examined two aspects of the adsorption process: the rate and the amount of adsorption. They measured the dynamic adsorption of both anionic and nonionic surfactants on Berea cores that were initially saturated with brine. They found that the relative adsorption levels for nonionic and anionic surfactants could be modeled by using a second-order reversible rate expression that reduced a Langmuir-type adsorption isotherm at equilibrium. It has been shown that the nature of the adsorption isotherm depends to a large extent on the type of surfactant used, the morphological and mineralogical characteristics of the rock, and the type of electrolytes present in solution (Singh and Pandey, 1982). The adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces (Leja, 1982; Stumm and Morgan, 1970). Positively charged cationic surfactant will be attracted to negatively charged surfaces, while negatively charged anionic surfactants will be attracted to positively charged surfaces. The salinity and pH of brine strongly affect the surface charge. For example, the surface charge of silica and calcite in water is positive at low pH, but negative at high pH. For silica, the surface becomes negatively charged when the pH is increased above about 2 – 3.7, whereas calcite does not become negatively charged until the pH is greater than about 8 –9.5 (Somasundaran, 1975; Stumm and Morgan, 1970). When the effects of brine chemistry are removed, silica tends to adsorb simple organic bases (cationic surfactant), while the carbonates tend to adsorb simple organic acids (anionic surfactant). This occurs because silica normally has a negatively
charged weak acidic surface in water near neutral pH, while the carbonates have positively charged weak basic surfaces. Several concerns about the chromatographic separation of the surfactant mixture have been expressed in the literature (Harwell et al., 1982, 1985; Mannhardt and Novosod, 1991; Trogus et al., 1979a,b; Scamhorn et al., 1982). Scamhorn et al. (1982) showed that adsorption is expected to increase with the surfactant’s hydrophobicity at the pre-micellar concentration range of surfactant, since an increase in hydrophobicity tends to drive the surfactant from the aqueous phase to the solid– liquid surface. Mannhardt and Novosod (1991) developed a model for adsorption of a surfactant mixture in flow through porous media. They concluded that the chromatographic movement of surfactant mixtures through the porous media depends not only on their affinity for the surface (selectivity), but also on their tendency to form micelles. The chromatographic separation of the surfactant mixture always occurs during chemical injections for enhanced oil recovery. Many researchers such as Trujillo (1983), Borwankar and Wasan (1986), and Rudin and Wasan (1992) have reported the mechanism of low dynamic IFT in crude oil – alkali systems. Acid present in the crude oil reacts with the alkaline solution to produce in situ surfactant (ionized acid) which lowers the oil – water IFT. The ionized acid is surface active and has a tendency to partition into the aqueous phase where it may form soap with sodium ions present in the aqueous phase at a high ionic strength. The soap has a trend to partition into the oil phase. The removal of the ionic acids from the interface can cause low dynamic IFT. It was found that, for a system of an oil –binary surfactant mixture, the oil – water interfacial tension depends on factors that can alter the surfactant partition between oil and water phase, such as the hydrophilic – lipophilic balance (HLB) of surfactant, the salinity, and the alkane carbon number of the oil (Zhang et al., 2002). Ng et al. (2002) investigated the IFT behavior of mixed surfactant systems. Their experimental results indicated that the presence of divalent ions (Ca2+) in the calcium-based lignosulfonates could enhance the interfacial activity (reducing oil – water interfacial tension) of the lignosulfonate petroleum sulfonate systems.
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In this article, adsorption – desorption-related interfacial phenomena (reduction of oil – water interfacial tension) and their effects on oil recovery are presented. Adsorption tests in Berea cores were conducted to obtain the adsorption –desorption behavior of a surfactant which was tested for enhanced oil recovery of a Saskatchewan medium-viscosity oil. The effects on oil – water IFT reduction of desorbed surfactant and of alkaline concentration were investigated. Four comparative coreflood tests were carried out to assess the potential of utilizing the desorbed surfactant in the extended waterflood after a chemical slug injection. The results of this research indicated that the potential exists and could improve the efficiency and economics of a chemical flood.
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2.2. Measurement of ORS-62HF concentration and IFT Changes in surfactant concentration during the adsorption – desorption tests were determined by using the two-phase titration method (ASTM, 1989; Reid et al., 1967). The upper phase is an anionic surfactant solution (aqueous phase); the lower phase is chloroform (oleic phase). Titration with a mixed indicator (Dimidium Bromide/Disulphine Blue) is applied. The colour change occurs in the chloroform layer. It is coloured pink in the presence of excess of anionic surfactant and blue with excess of cationic titrant. The endpoint is a grey-blue, which coincides with the complete transfer of a very small quantity of Disulphine Blue/cationic salt to the chloroform layer. The titration procedure is as follows:
2. Experimental In this work, adsorption – desorption-related interfacial tension behavior in chemical flooding and its effect on oil recovery were investigated by conducting: (1) adsorption tests in Berea cores, (2) oil –water interfacial tension measurements, and (3) coreflood tests. 2.1. Chemicals The surfactant used in this work is ORS-62HF, an alkyl-aryl sulfonic acid provided by Oil Chem (USA). This sulfonate surfactant is different from the conventional ones. The sulfonate group is attached to the end of the alkyl chain rather than directly attached to the aromatic ring and the aromatic ring is attached in the alkyl chain as a branch (Berger and Lee, 2002). The surfactant is a mixture of the same type of molecules with different lengths of carbon chains. The average molecular weight of the mixture is 420 with a distribution from 390 to 450. A medium – heavy oil and the formation water from a Saskatchewan oil reservoir were used. The oil has a viscosity of 15 mPas at the reservoir temperature (50 jC). Ultra-low IFTs have been obtained for the oil when ORS-62HF and NaOH were used in the formation brine (Huang and Dong, 2002; Zhang et al., 2003).
(1) Add 2 ml of surfactant solution, 25 ml of water, 15 ml of choloroform, and 10 ml of mixed indicator solution in a mixing cylinder. (2) Add a slightly less than equivalent amount of 0.004 mol/l of Hyamine 1622 solution into mixing cylinder and shake vigorously for 30 s. Then allow the cylinder to stand until the emulsion breaks and two phases appear. The lower layer is pink at this stage. (3) Continue the titration and shaking vigorously after each addition of titrant for at least 15 s. Near the endpoint, continue titration with drop-wise addition of titrant and shaking between additions, until the endpoint is reached. Record the volume of titrant added. The surfactant concentration was calculated by using the following equation: M¼
VH C VS
where M is the concentration of ORS-62HF, mol/l; VH is the volume of Hyamine 1622 solution, ml; C is the concentration of Hyamine 1622 solution, mol/l; and VS is the volume of anionic surfactant sample, ml. The spinning drop tensiometer was employed to measure oil –water interfacial tensions. All IFT measurements were performed at room temperature (22 F 0.5 jC).
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2.3. Surfactant adsorption and desorption tests 2.3.1. Preparation of cores The surfactant adsorption – desorption tests were performed in Berea cores with a permeability to air of 200 md and a porosity of 20%. The core plugs were 5.0 cm in length and 5.0 cm in diameter. After the cleaned Berea core was dried for 24 hrs at 120 jC, two distributors were attached to the core plug; these were covered with two ends connected with the injection and production line, respectively. The core plug, two distributors, and two ends were joined with a coating of resin as shown in Fig. 1. The core was vacuumed to a pressure of 10 10 6 Torr, then filled with CO2 and vacuumed again to 10 10 6 Torr. Finally, the formation brine was imbibed to saturate the core, followed by the injection of 0.5 pore volume (PV) brine. The core was then ready for the adsorption – desorption and coreflood tests. 2.3.2. Adsorption – desorption tests with single-phase injection The equilibrium adsorption of ORS-62HF in Berea cores was determined with the single-phase injection method. Surfactant solution was continuously injected into the core until the effluent surfactant concentration approached that of the injected surfactant solution. The effluent surfactant concentrations were analyzed by using the two-phase titration method. The equilibrium adsorption of the surfactant was estimated from the difference between the amount of surfactant injected and the amount in the effluent samples. A surfactant slug injection test was conducted at room temperature to characterize the adsorption –
desorption behavior of the surfactant. At an injection rate of 15 ml/h, 1.5 PV of alkaline – surfactant solution was injected followed by a continuous formation brine injection. The effluent samples were collected and analyzed for alkaline and surfactant concentrations. Oil – water interfacial tensions between the effluent samples and oil were measured. 2.4. Coreflood tests The purpose of the coreflood tests was to study the interfacial tension reduction as a result of desorption of surfactant during extended waterflood and its effect on oil recovery. Two sets of comparative coreflood tests were performed as follows: (1) Oil injection to the brine-saturated core to reach irreducible water saturation, (2) Initial waterflood to residual oil saturation, (3) Alkali – surfactant (A/S) slug (1.5 PV) injection, (4) Alkaline (A) slug injection, or (5) Extended brine flood. For each set of coreflood tests, one run had an alkaline injection after A/S slug injection and the other had an extended waterflood. In this way, the effect of alkali on the oil recovery by utilizing the desorbed surfactant in the extended waterflood was assessed. The oil and water in the effluent samples were separated in a high-speed centrifuge. Oil recoveries were determined by mass balance. The surfactant and alkaline concentrations in the water phase of the effluent samples were analyzed. The IFTs between the effluent water samples and oils (produced oil samples and fresh oil) were measured.
Fig. 1. Schematic of the coreflood system for adsorption and oil recovery tests.
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3. Results and discussion 3.1. Adsorption of surfactant in a continuous injection test Equilibrium adsorption of ORS-62HF in Berea core was measured by using a continuous injection method. The injected fluid was the formation water containing 0.2 wt.% ORS-62HF and 1.0 wt.% NaOH. Fig. 2 shows the normalized surfactant concentration in the effluent samples as a function of pore volume of produced fluid. The normalized surfactant concentration is the ratio of the surfactant concentration in the effluent samples to the original concentration. The normalized concentration reached 0.83 at about 15.5 PV fluid production and remained constant for another 6 PV. It was believed that the equilibrium monolayer adsorption had been reached and that the continued loss of surfactant after 15.5 PV was the result of multi-layer adsorption. The test was stopped at 21 PV production. The amount of adsorption of the surfactant was obtained by subtracting the amount remaining in the effluent samples from the amount of surfactant injected. The adsorption of the surfactant in the Berea core under the test conditions was determined to be 1.7 10 6 mol/g core (1.7 Amol/g). This level of adsorption appeared to be reasonable compared with the data reported in the literature. For example, an equilibrium adsorption of sodium dodecyl benzene sulfonate (C12H25C6H4SO3Na) on a Berea core was determined to be 2.0 Amol/g (Trogus et al., 1977).
Fig. 2. Normalized surfactant concentration vs. PV of fluid produced in the equilibrium adsorption test.
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3.2. Adsorption –desorption of surfactant in a slug injection test In various chemical injection processes where a dilute surfactant is applied, such as ASP flooding, the size of the chemical slug usually varies from 0.3 to 0.5 PV of the reservoir. Therefore, the adsorption of surfactant is far less than the equilibrium adsorption. Since the surfactant concentration is zero in an extended waterflood following the chemical slug, desorption of surfactant may occur. In order to investigate the adsorption – desorption behavior of the surfactant, an A/S slug injection test was conducted in a Berea core. As in the equilibrium adsorption test, the injected fluid was formation water containing 0.2 wt.% surfactant and 1.0 wt.% NaOH. When a slug of 0.5 PV of the above solution was injected, the amount of surfactant remaining in the effluent samples was negligible. This indicated that almost all of the surfactant in the injected solution was adsorbed by the core. In field applications, a chemical slug of 0.3 – 0.5 PV flows through different portions of the reservoir. Before a significant loss of the surfactant, such as in the regions near the injection well, the ratio of the entire chemical slug volume to a portion of the reservoir, e.g., 20% of the reservoir, can be higher than one. When the chemical slug flows through any portion of the reservoir, surfactant will be adsorbed first and then part of it will be desorbed into the water phase during the extended waterflood. The desorbed surfactant can also play a role in reducing the oil – water interfacial tension and improving oil recovery. In order to simulate this adsorption – desorption process, 1.5 PV of A/S solution was injected in the slug injection test. In this test, both the surfactant and the alkaline concentrations in the effluent samples were determined during the chemical slug injection and the extended waterflood process. Fig. 3 shows the normalized surfactant and alkaline concentrations in the effluent samples as a function of PV of produced fluid. The normalized surfactant concentration of surfactant reached a maximum of 0.12 at 2.7 PV of produced fluid. After that, the surfactant concentration in the effluent samples decreased slowly. At 15 PV, the normalized surfactant concentration decreased to about 0.01. From the mass balance, it was estimated that the amount of surfactant in the effluent was 37% of the total surfactant
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that the separation of surfactant from the A/S solution occurred by adsorption first and then desorption during the flow through the core. Since the molecular diffusion had little effect on the symmetry of the alkaline concentration curve, the long-lasting surfactant concentration curves resulted from desorption of the surfactant from the liquid – solid surface to the water phase. The surfactant used in this work was a mixture. Because of the difference in the affinities of different molecules to the liquid –rock interface, chromatographic separation occurred for the surfactant mixture. Fig. 3. Normalized surfactant and NaOH concentration vs. PV of fluid produced in alkaline/surfactant slug injection test.
injected in 21 PV of solution. The residual adsorption of the surfactant was 0.18 Amol/g, which was equivalent to 11% of the adsorption determined in the equilibrium adsorption test. The maximum of the normalized alkaline concentration was 0.8. According to the mass balance, 62% of injected NaOH was produced. Comparing the two curves of Fig. 3 shows: (1) The surfactant concentration peak came after that of NaOH; (2) the surfactant concentration curve was very asymmetrical with respect to PV of liquid produced; and (3) the alkaline concentration curve showed a nearly symmetrical curve with respect to PV of produced liquid. The normalized alkaline concentration decreased from 0.8 to 0.06 rapidly in only 2.5 PV of production. After 4.5 PV of production, alkaline concentration in the effluent was very low as compared to the original concentration. The major reasons for the delay of the small amount of alkaline production are molecular diffusion and dispersion at the rear of the A/S slug. The nearly symmetrical curve for NaOH concentration indicated that there was no retention of NaOH due to dead-end pore volume in the core (Green and Willhite, 1998). One can also conclude that there was no surfactant retention due to dead-end pore volume. After the maximum point, the normalized surfactant concentration decreased from 0.12 to 0.01 in about 12 PV of production. When NaOH concentration in the effluent samples reached its maximum, the surfactant concentration in the effluent samples was still increasing. This indicated
3.3. Adsorption –desorption related ITF behavior In order to examine the effect of the desorbed surfactant on reducing oil/water IFT, values of IFT between the effluent samples and the oil were measured. The results are shown in Fig. 4. The NaOH concentration curve was the part of the curve in Fig. 3 corresponding to 1.5 –14 PV of production. In the first two samples, NaOH concentration was about 0.8%, and the IFTs were lower than 1 dyn/cm. For the rest of samples in which NaOH concentration was lower than 0.01 wt.%, IFTs between these samples and oil were higher than 10 dyn/cm. For the oil – brine system used in this work, experimental investigation showed that adding alkali to the surfactant solution helped reduce oil/water IFT (Huang and Dong, 2002). To assess the effect of alkaline concentration (or pH) on the IFT between the oil and effluent samples, 1.0 wt.% NaOH was added to these effluent samples and the IFTs were measured. As shown in Fig. 5, when 1.0 wt.% NaOH was
Fig. 4. IFTs between effluent brine/original oil in the 1.5 PV A/S slug injection test.
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Fig. 5. IFTs between original oil and effluent water samples of the 1.5 PV A/S slug injection test. NaOH (1.0 wt%) was added to the effluent water samples.
added to those effluent water samples, the IFTs between them and the oil were decreased significantly. For all samples, the IFT was lower than 1 dyn/cm. For some samples, the IFT values were lower than 0.1 dyn/cm. An ultra-low IFT value as low as 10 3 dyn/cm was obtained with the effluent sample at about 8.4 PV fluid production. Recall that the normalized surfactant concentration in the effluent samples was lower than 0.1. The original surfactant concentration was 0.2 wt.%. The surfactant concentrations in all the effluent samples between 2 to 14 PV production were lower than 200 ppm. For example, the surfactant concentration was about 160 ppm for the samples between 3.8 and 6.0 PV production, 100 ppm for samples at about 8 PV production, and
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lower than 40 ppm after 12 PV production. These results indicate that the desorbed surfactant can be very effective in reducing the oil – water interfacial tension if an appropriate alkaline concentration is applied. Several studies have shown that a silica surface is negatively charged at a neutral pH value (Somasundaran, 1975; Stumm and Morgan, 1970). At a higher pH value, the silica surface is more negatively charged. There exists a repulsive interaction between the silica surfaces and the hydrophilic groups of anionic surfactant molecules. The anionic surfactant used in this work was a mixture of the same kind of surfactant molecules with different carbon chains. Theoretically, the longer the hydrophobic chain of a surfactant molecule, the less negative the hydrophilic group. The molecules which have a longer carbon chain will be more likely to be adsorbed on the silica surface. Therefore, the adsorbed surfactant molecules are different from those remaining in the water phase. This portion of surfactant seemed to be more effective in reducing oil – water IFT than those remaining in water phase. Since the reduction of oil –water interfacial tension is the most important mechanism of various chemical enhanced oil recovery processes, the utilization of the desorbed surfactant can further enhance the displacement of residual oil after the chemical slug and, consequently, improve the economics of the chemical flooding.
Table 1 Summary of coreflood tests Experimental parameters
Coreflood procedure (PV) A/S slug
A slug Recovery (%IOIP)
Waterflood A/S slug A slug Extended waterflood Injection rate (cm3/h) Alkaline concentration (wt.%) Surfactant concentration (wt.%) Injection rate (cm3/h) Alkaline concentration (wt.%) Waterflood A/S slug A slug Extended waterflood Total
Set 1
Set 2
Run 1
Run 2
Run 3
Run 4
3.0 1.5 – 3.0 15 1.0 0.2 15 – 21.2 18.0 – 9.6 48.8
3.0 1.5 3.0 – 15 1.0 0.2 15 1.0 21.2 20.3 20.5 – 62.0
2.2 1.5 – 3.0 10 0.5 0.2 10 – 18.0 12.0 – 5.0 35.0
2.2 1.5 3.0 – 10 0.5 0.2 1.0 – 18.2 12.2 11.0 – 41.0
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Fig. 7. Oil recovery curves of the second set of coreflood tests. Fig. 6. Oil recovery curves of the first set of coreflood tests.
3.4. Oil recovery by utilizing the desorbed surfactant in an extended waterflood Two sets of coreflood tests were conducted to assess the effect of the desorbed surfactant and alkaline concentration on oil recovery in extended waterfloods. The results of these tests are summarized in Table 1. In each set of tests, two coreflood runs were carried out for comparison. One coreflood run included initial waterflood, 1.5 PV A/S slug injection, and extended waterflood. The other coreflood run included initial waterflood, 1.5 PV A/S slug injection, and 3 PV of alkaline slug injection. Figs. 6 and 7 show the cumulative oil recovery vs. pore volume curves for Sets 1 and 2, respectively. The injection rate of the initial waterflood in all the tests was 10 ml/h. The injection rate of chemical solution (including the extended waterflood) was 15 ml/h in Set 1 (Fig. 6) and 10 ml/h in Set 2. In each set of tests, initial waterflood oil recoveries of the two runs (with and without alkaline slug after A/S slug injection) were nearly the same and the oil recoveries for the A/S slug injection stage were very close. This provided a starting point for comparing the effect on oil recovery of adding alkali in the extended waterflood. For the first set of tests shown in Fig. 6, the waterflood of both runs recovered 21% of initial oil in place (IOIP). In Run 1, A/S slug and extended waterflood together recovered 27.5% IOIP, and total oil recovery was 48.8% IOIP. In Run 2, A/S slug and alkaline slug together recovered 40.8% IOIP, and total oil recovery was 62% IOIP. The NaOH concentration in the extended waterflood of Run 2 was 1.0%. The
incremental oil recovery by extended waterflood was 13% IOIP more than Run 1. In the second set of coreflood runs, shown in Fig. 7, the NaOH concentration in the A/S slug was 0.5 wt.%. In Run 4, 0.5 wt.% NaOH was used in the extended waterflood. The waterflood recovered about 18% IOIP, which is slightly lower than for the first set. The initial A/S slug injection recovered about 17% IOIP for each of the two runs, which was much lower than the recovery obtained in Run 1 (27.5% IOIP) of the first set of tests. The injection of 3 PVof alkaline solution in Run 4 obtained an incremental oil recovery of 6% IOIP, compared to 13% IOIP obtained in Run 2 of Set 1. Low alkaline concentration and low chemical injection rate are the two major reasons for the lower oil recoveries in the A/S injections of Set 2 and in the extended waterflood of Run 4. In the following sections, it is shown that the oil – water IFT for the effluent samples with 0.5% NaOH was higher than that of the samples with 1.0% NaOH.
Fig. 8. NaOH concentrations in the effluent samples for the first set of coreflood tests.
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injection runs. It is shown below that adding NaOH in the extended waterflood helped to utilize effectively the desorbed surfactant in reducing IFT and improving oil recovery. To investigate the adsorption – desorption-related interfacial tension behavior in the extented waterflood, oil –water interfacial tensions were measured for the following systems:
Fig. 9. NaOH concentrations in the effluent samples for the second set of coreflood tests.
3.5. Analysis of interaction in desorbed surfactant/ alkali/oil systems For each coreflood test, effluent samples were collected at different run times. The oil and water of these samples were separated for analysis of chemical concentrations in the water phase and for oil – water IFT determination. The alkaline concentrations of the effluent water samples were measured by titration for the two sets of coreflood runs. The results are shown in Figs. 8 and 9 for Set 1 and Set 2, respectively. As expected, the NaOH concentration began to decrease after about 4.5 PV fluid production in the A/S-only injection runs. It continued to increase in the A/S + A
(1) IFTs between the oil and the water of the effluent samples for the two A/S + A runs (Runs 2 and 4). The oil and the water phases reached equilibrium for chemical reaction and the partition of surfactant in the oil and water phases. (2) IFTs between the original (fresh) oil and the effluent water samples for the two A/S + A runs. (3) IFTs between the oil and water of the effluent samples for the two A/S-only runs (Runs 1 and 3). However, 1.0% NaOH was added to the effluent water samples of Run 1 and 0.5% NaOH was added to the water samples of Run 3. (4) IFTs between the original oil and the effluent water samples for the two A/S-only runs (Runs 1 and 3). Similarly, NaOH was added to the effluent water samples as in (3). The measured IFT results for the first and second set of coreflood tests are shown in Figs. 10 and 11 respectively. In each figure, four type of curves
Fig. 10. IFT curves for oil (produced and original oil) and the effluent water samples of the first set of coreflood tests. NaOH (1.0 wt%) was added to the effluent water samples of Run 1.
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Fig. 11. IFT curves for oil (produced and original oil) and the effluent water samples of the second set of coreflood tests. NaOH (0.5 wt%) was added to the effluent water samples of Run 3.
corresponding to the above four systems are presented. The oil – water interfacial tension curves in Figs. 10 and 11 show a similar variation at different conditions (equilibrium oil vs. fresh oil, equilibrium water vs. water with newly added NaOH). For all the curves of Fig. 10, 1.0 wt.% NaOH was used, whereas for all the curves in Fig. 11, the NaOH concentration was 0.5 wt.%. Screening measurements for two selected effluent water samples showed that the oil – water IFT reached a minimum at about 1.0% NaOH. This is why oil –water IFTs for the effluent samples with 0.5% NaOH in Fig. 11 were higher than those of the samples with 1.0% NaOH in Fig. 10. Therefore, the discussion in the next sections focuses on the results presented in Fig. 10. The L-shaped IFT curve of Type (1) in Fig. 10 shows that low IFTs between the equilibrium oil and water (f 2 dyn/cm) were obtained during the extended waterflood when 1.0 wt.% NaOH was added, though the surfactant concentration in the water phase was extremely low. It is also noted that the IFTs of the effluent water – original oil systems (Type 2) were several times lower than those of the effluent brineproduced oil systems (Type 1). This can be explained as follows. In the Type 1 system, the oil and water reached equilibrium. There was no more reaction and partition across the oil – water interface. When a fresh (original) oil contacted produced water samples which contained both surfactant and alkali, both reaction between the alkali in the water and acids in the oil
and mass transfer across the oil – water interface occurred during the IFT measurements. It was these processes that caused the lower interfacial tension. It is believed that this is what happened in the alkaline slug injection after the A/S slug injection in Run 2. During the IFT measurements with the spinning drop method, variation of IFT with time was monitored. It was observed that the interfacial tension changed (decreased) with time very slowly. The values of IFT reported in this work were taken at time t = 30 min. The two V-shaped curves of Fig. 10 are IFTs between the oil (produced and original) and effluent
Fig. 12. ORS-62HF concentrations in the effluent samples of the first set of coreflood tests.
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caused low dynamic interfacial tensions, and displaced more oil.
4. Conclusions
Fig. 13. ORS-62HF concentration curves in the effluent samples in the second set of coreflood tests.
water samples of Run 1. In this run, an A/S slug was followed by extended waterflood without alkaline. However, 1.0 wt.% NaOH was added to the effluent water samples to assess its effect on the oil – water interfacial tension. The two curves show that when 1.0 wt.% NaOH was added to the effluent water samples which contained the desorbed surfactant, oil – water IFTs of some samples were reduced to as low as an order of 10 2 dyn/cm. Recall that the IFTs of the effluent water samples (no alkali) with original oil were higher than 10 dyn/cm (see Fig. 4). From these results, it is speculated that in coreflood Run 2, low or even ultra-low IFTs were obtained during the alkaline slug injection. The low or ultra-low IFTs resulted from (1) the interaction between NaOH and the oil, and (2) the synergy between the alkali and the desorbed surfactant. Surfactant concentrations in the effluent water samples of the four coreflood tests were also analyzed. The results for Set 1 and Set 2 of the coreflood tests are shown in Figs. 12 and 13, respectively. It is noted that in each figure, the surfactant concentrations in the effluent samples of the A/S + A run were lower than those of the A/Sonly runs. The introduction of NaOH into the brine – surfactant –rock system increased the salinity of the water phase and depressed the liquid – liquid and liquid – solid interface double layers. This caused more adsorption of surfactant at oil – water interfaces and partition of surfactant into the oil phase. It was these processes that occurred during the coreflood,
The results of single-phase injection tests indicated that the adsorption of surfactant ORS-62HF on Berea core at 21 PV of A/S solution (0.2 wt.% surfactant + 1 wt.% NaOH solution) injection was 1.7 Amol/g rock. With the injection of 1.5 PV of the same chemical solution, the residual adsorption of the same surfactant was 0.18 Amol/g rock, which was about 11% of saturated adsorption. Desorption of surfactant occurred during the brine injection after the A/S slug injection. Experimental results showed that the presence of both the desorbed surfactant and NaOH in the extended waterflood could reduce oil –water interfacial tension to about 2 dyn/cm for produced oil and water samples and about 0.5 dyn/cm for produced water and fresh oil. When the interfacial tension was measured between fresh alkaline solution (including desorbed surfactant) and the oil, ultra-low values were obtained for some samples. The latter mimicked the low interfacial tension scenario resulting from the synergy of the desorbed surfactant and NaOH in the extended waterflood. Four coreflood tests were carried out to assess the effect of the desorbed surfactant and alkaline concentration on oil recovery in extended waterfloods. The results confirmed the findings from the adsorption – desorption tests and interfacial tension measurements. After alkaline –surfactant slug injection, an additional 13% IOIP was recovered when the desorbed surfactant was utilized with the addition of 1.0 wt.% NaOH in the extended waterflood.
Acknowledgements Acknowledgement is extended to the Petroleum Technology Research Centre (PTRC) and Natural Science and Engineering Research Council (NSERC) of Canada for their financial support for this work. The authors wish to express their thanks to Talisman Energy for providing the oil and brine samples.
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References ASTM, 1989. Standard test method for synthetic anionic ingredient by cationic titration. Annual Book of ASTM Standards, vol. 15.04. American Society for Testing and Materials, West Conshohocken, PA, USA, pp. 320 – 323. Berger, P.D., Lee, C.H., 2002. Ultra-low concentration surfactants for sandstone and limestone floods. SPE 75186 presented at SPE/DOE improved oil recovery symposium held in Tulsa, OK, Apr. 13 – 17. Borwankar, R.P., Wasan, D.T., 1986. Dynamic interfacial tensions in acidic crude oil/caustic systems: Part I. A chemical diffusionkinetic model. AIChE J. 32 (3), 455 – 466. Gale, W.W., Sandvik, E.I., 1973. Tertiary surfactant flooding: petroleum sulfonate composition-efficiency studies. Soc. Pet. Eng. J., 191 – 199 (Aug.). Green, D.W., Willhite, G.P., 1998. Enhance oil recovery. SPR Textbook Series, vol. 6. Society of Petroleum Engineers, Richardson, TX. Harwell, J.H., Helfferich, F.G., Schechter, R.S., 1982. Effect of micelle formation on chromatographic movement of surfactant mixtures. AIChE J. 28, 448 – 459. Harwell, J.H., Schechter, R.S., Wade, W.H., 1985. Surfactant chromatographic movement: an experimental study. AIChE J. 31, 415 – 427. Huang, S., Dong, M., 2002. Alkaline/surfactant/polymer (ASP) flood potential in southwest Saskatchewan oil reservoirs. Paper 2002-109 presented at the Petroleum Society’s Canadian International Petroleum Conference 2002, Calgary, Alberta, Canada, June 11 – 13. Leja, J., 1982. Surface Chemistry of Froth Flotation. Plenum, New York. Mannhardt, K., Novosod, J.J., 1991. Chromatographic movement of surfactant mixtures in porous media. Chem. Eng. Sci. 46 (1), 75 – 83. Morgan, J.C., Schechter, R.S., Wade, W.H., 1979. Ultra-low interfacial tension and its implication in tertiary oil recovery. In: Mittal, K.L. (Ed.), Solution Chemistry of Surfactant. Plenum, New York, pp. 749 – 755. Ng, W.L., Rana, D., Neale, G.H., Hornof, V., 2002. Physicochemical behavior of mixed surfactant systems: petroleum sulfonate and lignosulfonate. J. Appl. Polym. Sci. 88, 860 – 865.
Reid, V.W., Longman, G.F., Heinerth, E., 1967. Determination of anionic active detergents by two phase titration. Tenside 4 (9), 292 – 304. Rudin, J., Wasan, D.T., 1992. Mechanisms for lowering of interfacial tension in alkali/acidic oil systems: I. Experimental studies. Colloids Surf. 68, 67 – 75. Scamhorn, J.F., Schechter, R.S., Wade, W.H., 1982. Adsorption of surfactants on mineral oxide surfaces from aqueous solution: I. Isomerically pure anionic surfactants. J. Colloid Interface Sci. 85, 463 – 478. Singh, V.S., Pandey, B.R., 1982. Role of adsorption in improved oil recovery by surfactant flooding. J. Sci. Ind. Res. 41, 54 – 57 (Jan.). Somasundaran, P., 1975. Interfacial chemistry of particulate flotation. In: Somasundaran, P., Grieves, R.B. (Eds.), Advances in Interfacial Phenomena of Particulate/Solution/Gas System: Applications to Flotation Research. AIChE Symposium Series, vol. 71, No. 150, pp. 1 – 15. Stumm, W., Morgan, J.J., 1970. Aquatic Chemistry Wiley, New York. Trogus, F.J., Sophony, T., Wade, W.H., 1977. Static and dynamic adsorption of anionic and non anionic surfactants. Soc. Pet. Eng. J. 17, 337 – 344 (Oct.). Trogus, F.J., Schechter, R.S., Pope, G.A., Wade, W.H., 1979a. Adsorption of mixed surfactant systems. J. Pet. Technol. 31, 769 – 778. Trogus, F.J., Schechter, R.S., Wade, W.H., 1979b. A new interpretation of adsorption maxima and minima. J. Colloid Interface Sci. 70, 293 – 305. Trujillo, E.M., 1983. The static and dynamic interfacial tensions between crude oils and caustic solutions. Soc. Pet. Eng. J. 23, 645 – 656. Zaitoun, A., Fonseca, C., Berger, P., Bazin, B., Monin, N., 2003. New surfactant for chemical flood in high salinity reservoir. SPE 80237 presented at the SPE International Symposium on Oilfield Chemistry held in Houston, TX, Feb. 5 – 7. Zhang, L., Luo, L., Zhao, S., Yu, J., 2002. Studies of synergism/ antagonism for lowering dynamic interfacial tensions in surfactant/alkali/acidic oil systems: Part 2. Synergism/antagonism in binary surfactant mixtures. J. Colloid Interface Sci. 251, 166 – 171. Zhang, Y.P., Huang, S., Dong, M., 2003. Determining the most profitable asp flood strategy for enhanced oil recovery. Paper 2003-015 presented at the Petroleum Society’s Canadian International Petroleum Conference, Calgary, Alberta, June 10 – 12.
Improved oil recovery by adsorption–desorption in chemical flooding Q. Liu a, M. Dong a,*, W. Zhou a, M. Ayub a, Y.P. Zhang b, S. Huang b b
a Faculty of Engineering, University of Regina, Regina, SK, Canada S4S 0A2 Saskatchewan Research Council, 6 Research Drive, Regina, SK, Canada S4S 3Y9
Received 10 April 2003; accepted 18 December 2003
Abstract Surfactant loss is one of the major concerns with chemical oil recovery processes in which surfactant is one of the components of the chemical formula. Surfactant loss due to adsorption on the reservoir rocks weakens the effectiveness of the injected chemical slug in reducing oil – water interfacial tension (IFT) and makes the process uneconomical. Adsorption-related interfacial tension behavior and its effect on oil recovery has not been understood completely. This paper reports the investigation of oil – water IFT behavior when the chromatographic separation of the surfactant mixture occurs during surfactant/alkaline corefloods. In this work, surfactant and alkaline concentrations in the effluent of corefloods and oil – water interfacial tension were determined under different injection strategies. It was found that, in an extended waterflood following an alkaline-surfactant slug injection, surfactant desorbed into the water phase. This desorption of surfactant lasted for a long period of the waterflood. Although the concentration of the desorbed surfactant in the extended waterflood was very low, an ultra-low oil – water IFT was obtained by using a suitable alkaline concentration. Coreflood results showed that an additional 13% of the initial oil in place (IOIP) was recovered after the alkaline – surfactant injection by the synergism of the desorbed surfactant and alkaline. This result indicates that the efficiency and economics of a chemical flood could be improved by utilizing the desorbed surfactant during extended waterflood processes. D 2004 Published by Elsevier B.V. Keywords: Adsorption; Desorption; Surfactant; Interfacial tension; Chemical flood; Enhanced oil recovery; Coreflood
1. Introduction In order to mobilize residual oil trapped by capillary forces in oil reservoirs, many enhanced oil recovery (EOR) methods rely on reducing the oil – water interfacial tension (IFT) to extremely low values, often to 10 2 dyn/cm or less (Morgan et al., * Corresponding author. Tel.: +1-306-337-2269; fax: +1-306585-4485. E-mail address: [email protected] (M. Dong). 0920-4105/$ - see front matter D 2004 Published by Elsevier B.V. doi:10.1016/j.petrol.2003.12.017
1979). Examples of improved oil recovery processes utilizing surfactants include micellar polymer flooding, alkaline/surfactant/polymer (ASP) flooding, and alkaline surfactant foam flooding (Berger and Lee, 2002). Surfactant reduces the IFT between the brine and residual oil and therefore increases the capillary number. The capillary number, Nc, is used to express the ratio of viscous forces to capillary forces acting on entrapped oil drops within porous media. A capillary number of about 10 6 is found after a typical waterflood, and this number can be increased by two or
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three orders of magnitude when the IFT is reduced from about 20 –30 to 10 2 dyne/cm. In chemical flooding, surfactants are inevitably adsorbed on the surface of reservoir rock by the rock – oil –brine interaction. Surfactant adsorption is one of the important factors governing the economic feasibility of chemical flooding processes (Gale and Sandvik, 1973). Zaitoun et al. (2003) studied the adsorption of a surfactant in brine with high salinity and high concentration of divalent ions. Their experimental results showed that the adsorption of a surfactant (primary surfactant) could be reduced significantly by the use of another surfactant that acted as an anti-adsorption additive. Trogus et al. (1977) examined two aspects of the adsorption process: the rate and the amount of adsorption. They measured the dynamic adsorption of both anionic and nonionic surfactants on Berea cores that were initially saturated with brine. They found that the relative adsorption levels for nonionic and anionic surfactants could be modeled by using a second-order reversible rate expression that reduced a Langmuir-type adsorption isotherm at equilibrium. It has been shown that the nature of the adsorption isotherm depends to a large extent on the type of surfactant used, the morphological and mineralogical characteristics of the rock, and the type of electrolytes present in solution (Singh and Pandey, 1982). The adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces (Leja, 1982; Stumm and Morgan, 1970). Positively charged cationic surfactant will be attracted to negatively charged surfaces, while negatively charged anionic surfactants will be attracted to positively charged surfaces. The salinity and pH of brine strongly affect the surface charge. For example, the surface charge of silica and calcite in water is positive at low pH, but negative at high pH. For silica, the surface becomes negatively charged when the pH is increased above about 2 – 3.7, whereas calcite does not become negatively charged until the pH is greater than about 8 –9.5 (Somasundaran, 1975; Stumm and Morgan, 1970). When the effects of brine chemistry are removed, silica tends to adsorb simple organic bases (cationic surfactant), while the carbonates tend to adsorb simple organic acids (anionic surfactant). This occurs because silica normally has a negatively
charged weak acidic surface in water near neutral pH, while the carbonates have positively charged weak basic surfaces. Several concerns about the chromatographic separation of the surfactant mixture have been expressed in the literature (Harwell et al., 1982, 1985; Mannhardt and Novosod, 1991; Trogus et al., 1979a,b; Scamhorn et al., 1982). Scamhorn et al. (1982) showed that adsorption is expected to increase with the surfactant’s hydrophobicity at the pre-micellar concentration range of surfactant, since an increase in hydrophobicity tends to drive the surfactant from the aqueous phase to the solid– liquid surface. Mannhardt and Novosod (1991) developed a model for adsorption of a surfactant mixture in flow through porous media. They concluded that the chromatographic movement of surfactant mixtures through the porous media depends not only on their affinity for the surface (selectivity), but also on their tendency to form micelles. The chromatographic separation of the surfactant mixture always occurs during chemical injections for enhanced oil recovery. Many researchers such as Trujillo (1983), Borwankar and Wasan (1986), and Rudin and Wasan (1992) have reported the mechanism of low dynamic IFT in crude oil – alkali systems. Acid present in the crude oil reacts with the alkaline solution to produce in situ surfactant (ionized acid) which lowers the oil – water IFT. The ionized acid is surface active and has a tendency to partition into the aqueous phase where it may form soap with sodium ions present in the aqueous phase at a high ionic strength. The soap has a trend to partition into the oil phase. The removal of the ionic acids from the interface can cause low dynamic IFT. It was found that, for a system of an oil –binary surfactant mixture, the oil – water interfacial tension depends on factors that can alter the surfactant partition between oil and water phase, such as the hydrophilic – lipophilic balance (HLB) of surfactant, the salinity, and the alkane carbon number of the oil (Zhang et al., 2002). Ng et al. (2002) investigated the IFT behavior of mixed surfactant systems. Their experimental results indicated that the presence of divalent ions (Ca2+) in the calcium-based lignosulfonates could enhance the interfacial activity (reducing oil – water interfacial tension) of the lignosulfonate petroleum sulfonate systems.
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In this article, adsorption – desorption-related interfacial phenomena (reduction of oil – water interfacial tension) and their effects on oil recovery are presented. Adsorption tests in Berea cores were conducted to obtain the adsorption –desorption behavior of a surfactant which was tested for enhanced oil recovery of a Saskatchewan medium-viscosity oil. The effects on oil – water IFT reduction of desorbed surfactant and of alkaline concentration were investigated. Four comparative coreflood tests were carried out to assess the potential of utilizing the desorbed surfactant in the extended waterflood after a chemical slug injection. The results of this research indicated that the potential exists and could improve the efficiency and economics of a chemical flood.
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2.2. Measurement of ORS-62HF concentration and IFT Changes in surfactant concentration during the adsorption – desorption tests were determined by using the two-phase titration method (ASTM, 1989; Reid et al., 1967). The upper phase is an anionic surfactant solution (aqueous phase); the lower phase is chloroform (oleic phase). Titration with a mixed indicator (Dimidium Bromide/Disulphine Blue) is applied. The colour change occurs in the chloroform layer. It is coloured pink in the presence of excess of anionic surfactant and blue with excess of cationic titrant. The endpoint is a grey-blue, which coincides with the complete transfer of a very small quantity of Disulphine Blue/cationic salt to the chloroform layer. The titration procedure is as follows:
2. Experimental In this work, adsorption – desorption-related interfacial tension behavior in chemical flooding and its effect on oil recovery were investigated by conducting: (1) adsorption tests in Berea cores, (2) oil –water interfacial tension measurements, and (3) coreflood tests. 2.1. Chemicals The surfactant used in this work is ORS-62HF, an alkyl-aryl sulfonic acid provided by Oil Chem (USA). This sulfonate surfactant is different from the conventional ones. The sulfonate group is attached to the end of the alkyl chain rather than directly attached to the aromatic ring and the aromatic ring is attached in the alkyl chain as a branch (Berger and Lee, 2002). The surfactant is a mixture of the same type of molecules with different lengths of carbon chains. The average molecular weight of the mixture is 420 with a distribution from 390 to 450. A medium – heavy oil and the formation water from a Saskatchewan oil reservoir were used. The oil has a viscosity of 15 mPas at the reservoir temperature (50 jC). Ultra-low IFTs have been obtained for the oil when ORS-62HF and NaOH were used in the formation brine (Huang and Dong, 2002; Zhang et al., 2003).
(1) Add 2 ml of surfactant solution, 25 ml of water, 15 ml of choloroform, and 10 ml of mixed indicator solution in a mixing cylinder. (2) Add a slightly less than equivalent amount of 0.004 mol/l of Hyamine 1622 solution into mixing cylinder and shake vigorously for 30 s. Then allow the cylinder to stand until the emulsion breaks and two phases appear. The lower layer is pink at this stage. (3) Continue the titration and shaking vigorously after each addition of titrant for at least 15 s. Near the endpoint, continue titration with drop-wise addition of titrant and shaking between additions, until the endpoint is reached. Record the volume of titrant added. The surfactant concentration was calculated by using the following equation: M¼
VH C VS
where M is the concentration of ORS-62HF, mol/l; VH is the volume of Hyamine 1622 solution, ml; C is the concentration of Hyamine 1622 solution, mol/l; and VS is the volume of anionic surfactant sample, ml. The spinning drop tensiometer was employed to measure oil –water interfacial tensions. All IFT measurements were performed at room temperature (22 F 0.5 jC).
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2.3. Surfactant adsorption and desorption tests 2.3.1. Preparation of cores The surfactant adsorption – desorption tests were performed in Berea cores with a permeability to air of 200 md and a porosity of 20%. The core plugs were 5.0 cm in length and 5.0 cm in diameter. After the cleaned Berea core was dried for 24 hrs at 120 jC, two distributors were attached to the core plug; these were covered with two ends connected with the injection and production line, respectively. The core plug, two distributors, and two ends were joined with a coating of resin as shown in Fig. 1. The core was vacuumed to a pressure of 10 10 6 Torr, then filled with CO2 and vacuumed again to 10 10 6 Torr. Finally, the formation brine was imbibed to saturate the core, followed by the injection of 0.5 pore volume (PV) brine. The core was then ready for the adsorption – desorption and coreflood tests. 2.3.2. Adsorption – desorption tests with single-phase injection The equilibrium adsorption of ORS-62HF in Berea cores was determined with the single-phase injection method. Surfactant solution was continuously injected into the core until the effluent surfactant concentration approached that of the injected surfactant solution. The effluent surfactant concentrations were analyzed by using the two-phase titration method. The equilibrium adsorption of the surfactant was estimated from the difference between the amount of surfactant injected and the amount in the effluent samples. A surfactant slug injection test was conducted at room temperature to characterize the adsorption –
desorption behavior of the surfactant. At an injection rate of 15 ml/h, 1.5 PV of alkaline – surfactant solution was injected followed by a continuous formation brine injection. The effluent samples were collected and analyzed for alkaline and surfactant concentrations. Oil – water interfacial tensions between the effluent samples and oil were measured. 2.4. Coreflood tests The purpose of the coreflood tests was to study the interfacial tension reduction as a result of desorption of surfactant during extended waterflood and its effect on oil recovery. Two sets of comparative coreflood tests were performed as follows: (1) Oil injection to the brine-saturated core to reach irreducible water saturation, (2) Initial waterflood to residual oil saturation, (3) Alkali – surfactant (A/S) slug (1.5 PV) injection, (4) Alkaline (A) slug injection, or (5) Extended brine flood. For each set of coreflood tests, one run had an alkaline injection after A/S slug injection and the other had an extended waterflood. In this way, the effect of alkali on the oil recovery by utilizing the desorbed surfactant in the extended waterflood was assessed. The oil and water in the effluent samples were separated in a high-speed centrifuge. Oil recoveries were determined by mass balance. The surfactant and alkaline concentrations in the water phase of the effluent samples were analyzed. The IFTs between the effluent water samples and oils (produced oil samples and fresh oil) were measured.
Fig. 1. Schematic of the coreflood system for adsorption and oil recovery tests.
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3. Results and discussion 3.1. Adsorption of surfactant in a continuous injection test Equilibrium adsorption of ORS-62HF in Berea core was measured by using a continuous injection method. The injected fluid was the formation water containing 0.2 wt.% ORS-62HF and 1.0 wt.% NaOH. Fig. 2 shows the normalized surfactant concentration in the effluent samples as a function of pore volume of produced fluid. The normalized surfactant concentration is the ratio of the surfactant concentration in the effluent samples to the original concentration. The normalized concentration reached 0.83 at about 15.5 PV fluid production and remained constant for another 6 PV. It was believed that the equilibrium monolayer adsorption had been reached and that the continued loss of surfactant after 15.5 PV was the result of multi-layer adsorption. The test was stopped at 21 PV production. The amount of adsorption of the surfactant was obtained by subtracting the amount remaining in the effluent samples from the amount of surfactant injected. The adsorption of the surfactant in the Berea core under the test conditions was determined to be 1.7 10 6 mol/g core (1.7 Amol/g). This level of adsorption appeared to be reasonable compared with the data reported in the literature. For example, an equilibrium adsorption of sodium dodecyl benzene sulfonate (C12H25C6H4SO3Na) on a Berea core was determined to be 2.0 Amol/g (Trogus et al., 1977).
Fig. 2. Normalized surfactant concentration vs. PV of fluid produced in the equilibrium adsorption test.
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3.2. Adsorption –desorption of surfactant in a slug injection test In various chemical injection processes where a dilute surfactant is applied, such as ASP flooding, the size of the chemical slug usually varies from 0.3 to 0.5 PV of the reservoir. Therefore, the adsorption of surfactant is far less than the equilibrium adsorption. Since the surfactant concentration is zero in an extended waterflood following the chemical slug, desorption of surfactant may occur. In order to investigate the adsorption – desorption behavior of the surfactant, an A/S slug injection test was conducted in a Berea core. As in the equilibrium adsorption test, the injected fluid was formation water containing 0.2 wt.% surfactant and 1.0 wt.% NaOH. When a slug of 0.5 PV of the above solution was injected, the amount of surfactant remaining in the effluent samples was negligible. This indicated that almost all of the surfactant in the injected solution was adsorbed by the core. In field applications, a chemical slug of 0.3 – 0.5 PV flows through different portions of the reservoir. Before a significant loss of the surfactant, such as in the regions near the injection well, the ratio of the entire chemical slug volume to a portion of the reservoir, e.g., 20% of the reservoir, can be higher than one. When the chemical slug flows through any portion of the reservoir, surfactant will be adsorbed first and then part of it will be desorbed into the water phase during the extended waterflood. The desorbed surfactant can also play a role in reducing the oil – water interfacial tension and improving oil recovery. In order to simulate this adsorption – desorption process, 1.5 PV of A/S solution was injected in the slug injection test. In this test, both the surfactant and the alkaline concentrations in the effluent samples were determined during the chemical slug injection and the extended waterflood process. Fig. 3 shows the normalized surfactant and alkaline concentrations in the effluent samples as a function of PV of produced fluid. The normalized surfactant concentration of surfactant reached a maximum of 0.12 at 2.7 PV of produced fluid. After that, the surfactant concentration in the effluent samples decreased slowly. At 15 PV, the normalized surfactant concentration decreased to about 0.01. From the mass balance, it was estimated that the amount of surfactant in the effluent was 37% of the total surfactant
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that the separation of surfactant from the A/S solution occurred by adsorption first and then desorption during the flow through the core. Since the molecular diffusion had little effect on the symmetry of the alkaline concentration curve, the long-lasting surfactant concentration curves resulted from desorption of the surfactant from the liquid – solid surface to the water phase. The surfactant used in this work was a mixture. Because of the difference in the affinities of different molecules to the liquid –rock interface, chromatographic separation occurred for the surfactant mixture. Fig. 3. Normalized surfactant and NaOH concentration vs. PV of fluid produced in alkaline/surfactant slug injection test.
injected in 21 PV of solution. The residual adsorption of the surfactant was 0.18 Amol/g, which was equivalent to 11% of the adsorption determined in the equilibrium adsorption test. The maximum of the normalized alkaline concentration was 0.8. According to the mass balance, 62% of injected NaOH was produced. Comparing the two curves of Fig. 3 shows: (1) The surfactant concentration peak came after that of NaOH; (2) the surfactant concentration curve was very asymmetrical with respect to PV of liquid produced; and (3) the alkaline concentration curve showed a nearly symmetrical curve with respect to PV of produced liquid. The normalized alkaline concentration decreased from 0.8 to 0.06 rapidly in only 2.5 PV of production. After 4.5 PV of production, alkaline concentration in the effluent was very low as compared to the original concentration. The major reasons for the delay of the small amount of alkaline production are molecular diffusion and dispersion at the rear of the A/S slug. The nearly symmetrical curve for NaOH concentration indicated that there was no retention of NaOH due to dead-end pore volume in the core (Green and Willhite, 1998). One can also conclude that there was no surfactant retention due to dead-end pore volume. After the maximum point, the normalized surfactant concentration decreased from 0.12 to 0.01 in about 12 PV of production. When NaOH concentration in the effluent samples reached its maximum, the surfactant concentration in the effluent samples was still increasing. This indicated
3.3. Adsorption –desorption related ITF behavior In order to examine the effect of the desorbed surfactant on reducing oil/water IFT, values of IFT between the effluent samples and the oil were measured. The results are shown in Fig. 4. The NaOH concentration curve was the part of the curve in Fig. 3 corresponding to 1.5 –14 PV of production. In the first two samples, NaOH concentration was about 0.8%, and the IFTs were lower than 1 dyn/cm. For the rest of samples in which NaOH concentration was lower than 0.01 wt.%, IFTs between these samples and oil were higher than 10 dyn/cm. For the oil – brine system used in this work, experimental investigation showed that adding alkali to the surfactant solution helped reduce oil/water IFT (Huang and Dong, 2002). To assess the effect of alkaline concentration (or pH) on the IFT between the oil and effluent samples, 1.0 wt.% NaOH was added to these effluent samples and the IFTs were measured. As shown in Fig. 5, when 1.0 wt.% NaOH was
Fig. 4. IFTs between effluent brine/original oil in the 1.5 PV A/S slug injection test.
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Fig. 5. IFTs between original oil and effluent water samples of the 1.5 PV A/S slug injection test. NaOH (1.0 wt%) was added to the effluent water samples.
added to those effluent water samples, the IFTs between them and the oil were decreased significantly. For all samples, the IFT was lower than 1 dyn/cm. For some samples, the IFT values were lower than 0.1 dyn/cm. An ultra-low IFT value as low as 10 3 dyn/cm was obtained with the effluent sample at about 8.4 PV fluid production. Recall that the normalized surfactant concentration in the effluent samples was lower than 0.1. The original surfactant concentration was 0.2 wt.%. The surfactant concentrations in all the effluent samples between 2 to 14 PV production were lower than 200 ppm. For example, the surfactant concentration was about 160 ppm for the samples between 3.8 and 6.0 PV production, 100 ppm for samples at about 8 PV production, and
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lower than 40 ppm after 12 PV production. These results indicate that the desorbed surfactant can be very effective in reducing the oil – water interfacial tension if an appropriate alkaline concentration is applied. Several studies have shown that a silica surface is negatively charged at a neutral pH value (Somasundaran, 1975; Stumm and Morgan, 1970). At a higher pH value, the silica surface is more negatively charged. There exists a repulsive interaction between the silica surfaces and the hydrophilic groups of anionic surfactant molecules. The anionic surfactant used in this work was a mixture of the same kind of surfactant molecules with different carbon chains. Theoretically, the longer the hydrophobic chain of a surfactant molecule, the less negative the hydrophilic group. The molecules which have a longer carbon chain will be more likely to be adsorbed on the silica surface. Therefore, the adsorbed surfactant molecules are different from those remaining in the water phase. This portion of surfactant seemed to be more effective in reducing oil – water IFT than those remaining in water phase. Since the reduction of oil –water interfacial tension is the most important mechanism of various chemical enhanced oil recovery processes, the utilization of the desorbed surfactant can further enhance the displacement of residual oil after the chemical slug and, consequently, improve the economics of the chemical flooding.
Table 1 Summary of coreflood tests Experimental parameters
Coreflood procedure (PV) A/S slug
A slug Recovery (%IOIP)
Waterflood A/S slug A slug Extended waterflood Injection rate (cm3/h) Alkaline concentration (wt.%) Surfactant concentration (wt.%) Injection rate (cm3/h) Alkaline concentration (wt.%) Waterflood A/S slug A slug Extended waterflood Total
Set 1
Set 2
Run 1
Run 2
Run 3
Run 4
3.0 1.5 – 3.0 15 1.0 0.2 15 – 21.2 18.0 – 9.6 48.8
3.0 1.5 3.0 – 15 1.0 0.2 15 1.0 21.2 20.3 20.5 – 62.0
2.2 1.5 – 3.0 10 0.5 0.2 10 – 18.0 12.0 – 5.0 35.0
2.2 1.5 3.0 – 10 0.5 0.2 1.0 – 18.2 12.2 11.0 – 41.0
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Fig. 7. Oil recovery curves of the second set of coreflood tests. Fig. 6. Oil recovery curves of the first set of coreflood tests.
3.4. Oil recovery by utilizing the desorbed surfactant in an extended waterflood Two sets of coreflood tests were conducted to assess the effect of the desorbed surfactant and alkaline concentration on oil recovery in extended waterfloods. The results of these tests are summarized in Table 1. In each set of tests, two coreflood runs were carried out for comparison. One coreflood run included initial waterflood, 1.5 PV A/S slug injection, and extended waterflood. The other coreflood run included initial waterflood, 1.5 PV A/S slug injection, and 3 PV of alkaline slug injection. Figs. 6 and 7 show the cumulative oil recovery vs. pore volume curves for Sets 1 and 2, respectively. The injection rate of the initial waterflood in all the tests was 10 ml/h. The injection rate of chemical solution (including the extended waterflood) was 15 ml/h in Set 1 (Fig. 6) and 10 ml/h in Set 2. In each set of tests, initial waterflood oil recoveries of the two runs (with and without alkaline slug after A/S slug injection) were nearly the same and the oil recoveries for the A/S slug injection stage were very close. This provided a starting point for comparing the effect on oil recovery of adding alkali in the extended waterflood. For the first set of tests shown in Fig. 6, the waterflood of both runs recovered 21% of initial oil in place (IOIP). In Run 1, A/S slug and extended waterflood together recovered 27.5% IOIP, and total oil recovery was 48.8% IOIP. In Run 2, A/S slug and alkaline slug together recovered 40.8% IOIP, and total oil recovery was 62% IOIP. The NaOH concentration in the extended waterflood of Run 2 was 1.0%. The
incremental oil recovery by extended waterflood was 13% IOIP more than Run 1. In the second set of coreflood runs, shown in Fig. 7, the NaOH concentration in the A/S slug was 0.5 wt.%. In Run 4, 0.5 wt.% NaOH was used in the extended waterflood. The waterflood recovered about 18% IOIP, which is slightly lower than for the first set. The initial A/S slug injection recovered about 17% IOIP for each of the two runs, which was much lower than the recovery obtained in Run 1 (27.5% IOIP) of the first set of tests. The injection of 3 PVof alkaline solution in Run 4 obtained an incremental oil recovery of 6% IOIP, compared to 13% IOIP obtained in Run 2 of Set 1. Low alkaline concentration and low chemical injection rate are the two major reasons for the lower oil recoveries in the A/S injections of Set 2 and in the extended waterflood of Run 4. In the following sections, it is shown that the oil – water IFT for the effluent samples with 0.5% NaOH was higher than that of the samples with 1.0% NaOH.
Fig. 8. NaOH concentrations in the effluent samples for the first set of coreflood tests.
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injection runs. It is shown below that adding NaOH in the extended waterflood helped to utilize effectively the desorbed surfactant in reducing IFT and improving oil recovery. To investigate the adsorption – desorption-related interfacial tension behavior in the extented waterflood, oil –water interfacial tensions were measured for the following systems:
Fig. 9. NaOH concentrations in the effluent samples for the second set of coreflood tests.
3.5. Analysis of interaction in desorbed surfactant/ alkali/oil systems For each coreflood test, effluent samples were collected at different run times. The oil and water of these samples were separated for analysis of chemical concentrations in the water phase and for oil – water IFT determination. The alkaline concentrations of the effluent water samples were measured by titration for the two sets of coreflood runs. The results are shown in Figs. 8 and 9 for Set 1 and Set 2, respectively. As expected, the NaOH concentration began to decrease after about 4.5 PV fluid production in the A/S-only injection runs. It continued to increase in the A/S + A
(1) IFTs between the oil and the water of the effluent samples for the two A/S + A runs (Runs 2 and 4). The oil and the water phases reached equilibrium for chemical reaction and the partition of surfactant in the oil and water phases. (2) IFTs between the original (fresh) oil and the effluent water samples for the two A/S + A runs. (3) IFTs between the oil and water of the effluent samples for the two A/S-only runs (Runs 1 and 3). However, 1.0% NaOH was added to the effluent water samples of Run 1 and 0.5% NaOH was added to the water samples of Run 3. (4) IFTs between the original oil and the effluent water samples for the two A/S-only runs (Runs 1 and 3). Similarly, NaOH was added to the effluent water samples as in (3). The measured IFT results for the first and second set of coreflood tests are shown in Figs. 10 and 11 respectively. In each figure, four type of curves
Fig. 10. IFT curves for oil (produced and original oil) and the effluent water samples of the first set of coreflood tests. NaOH (1.0 wt%) was added to the effluent water samples of Run 1.
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Fig. 11. IFT curves for oil (produced and original oil) and the effluent water samples of the second set of coreflood tests. NaOH (0.5 wt%) was added to the effluent water samples of Run 3.
corresponding to the above four systems are presented. The oil – water interfacial tension curves in Figs. 10 and 11 show a similar variation at different conditions (equilibrium oil vs. fresh oil, equilibrium water vs. water with newly added NaOH). For all the curves of Fig. 10, 1.0 wt.% NaOH was used, whereas for all the curves in Fig. 11, the NaOH concentration was 0.5 wt.%. Screening measurements for two selected effluent water samples showed that the oil – water IFT reached a minimum at about 1.0% NaOH. This is why oil –water IFTs for the effluent samples with 0.5% NaOH in Fig. 11 were higher than those of the samples with 1.0% NaOH in Fig. 10. Therefore, the discussion in the next sections focuses on the results presented in Fig. 10. The L-shaped IFT curve of Type (1) in Fig. 10 shows that low IFTs between the equilibrium oil and water (f 2 dyn/cm) were obtained during the extended waterflood when 1.0 wt.% NaOH was added, though the surfactant concentration in the water phase was extremely low. It is also noted that the IFTs of the effluent water – original oil systems (Type 2) were several times lower than those of the effluent brineproduced oil systems (Type 1). This can be explained as follows. In the Type 1 system, the oil and water reached equilibrium. There was no more reaction and partition across the oil – water interface. When a fresh (original) oil contacted produced water samples which contained both surfactant and alkali, both reaction between the alkali in the water and acids in the oil
and mass transfer across the oil – water interface occurred during the IFT measurements. It was these processes that caused the lower interfacial tension. It is believed that this is what happened in the alkaline slug injection after the A/S slug injection in Run 2. During the IFT measurements with the spinning drop method, variation of IFT with time was monitored. It was observed that the interfacial tension changed (decreased) with time very slowly. The values of IFT reported in this work were taken at time t = 30 min. The two V-shaped curves of Fig. 10 are IFTs between the oil (produced and original) and effluent
Fig. 12. ORS-62HF concentrations in the effluent samples of the first set of coreflood tests.
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caused low dynamic interfacial tensions, and displaced more oil.
4. Conclusions
Fig. 13. ORS-62HF concentration curves in the effluent samples in the second set of coreflood tests.
water samples of Run 1. In this run, an A/S slug was followed by extended waterflood without alkaline. However, 1.0 wt.% NaOH was added to the effluent water samples to assess its effect on the oil – water interfacial tension. The two curves show that when 1.0 wt.% NaOH was added to the effluent water samples which contained the desorbed surfactant, oil – water IFTs of some samples were reduced to as low as an order of 10 2 dyn/cm. Recall that the IFTs of the effluent water samples (no alkali) with original oil were higher than 10 dyn/cm (see Fig. 4). From these results, it is speculated that in coreflood Run 2, low or even ultra-low IFTs were obtained during the alkaline slug injection. The low or ultra-low IFTs resulted from (1) the interaction between NaOH and the oil, and (2) the synergy between the alkali and the desorbed surfactant. Surfactant concentrations in the effluent water samples of the four coreflood tests were also analyzed. The results for Set 1 and Set 2 of the coreflood tests are shown in Figs. 12 and 13, respectively. It is noted that in each figure, the surfactant concentrations in the effluent samples of the A/S + A run were lower than those of the A/Sonly runs. The introduction of NaOH into the brine – surfactant –rock system increased the salinity of the water phase and depressed the liquid – liquid and liquid – solid interface double layers. This caused more adsorption of surfactant at oil – water interfaces and partition of surfactant into the oil phase. It was these processes that occurred during the coreflood,
The results of single-phase injection tests indicated that the adsorption of surfactant ORS-62HF on Berea core at 21 PV of A/S solution (0.2 wt.% surfactant + 1 wt.% NaOH solution) injection was 1.7 Amol/g rock. With the injection of 1.5 PV of the same chemical solution, the residual adsorption of the same surfactant was 0.18 Amol/g rock, which was about 11% of saturated adsorption. Desorption of surfactant occurred during the brine injection after the A/S slug injection. Experimental results showed that the presence of both the desorbed surfactant and NaOH in the extended waterflood could reduce oil –water interfacial tension to about 2 dyn/cm for produced oil and water samples and about 0.5 dyn/cm for produced water and fresh oil. When the interfacial tension was measured between fresh alkaline solution (including desorbed surfactant) and the oil, ultra-low values were obtained for some samples. The latter mimicked the low interfacial tension scenario resulting from the synergy of the desorbed surfactant and NaOH in the extended waterflood. Four coreflood tests were carried out to assess the effect of the desorbed surfactant and alkaline concentration on oil recovery in extended waterfloods. The results confirmed the findings from the adsorption – desorption tests and interfacial tension measurements. After alkaline –surfactant slug injection, an additional 13% IOIP was recovered when the desorbed surfactant was utilized with the addition of 1.0 wt.% NaOH in the extended waterflood.
Acknowledgements Acknowledgement is extended to the Petroleum Technology Research Centre (PTRC) and Natural Science and Engineering Research Council (NSERC) of Canada for their financial support for this work. The authors wish to express their thanks to Talisman Energy for providing the oil and brine samples.
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