Transp Porous Med (2011) 90:589–604 DOI 10.1007/s11242-011-9805-y

Adsorption–Desorption of Surfactant for Enhanced Oil Recovery Subrata Borgohain Gogoi

Received: 5 June 2010 / Accepted: 9 July 2011 / Published online: 3 August 2011 © Springer Science+Business Media B.V. 2011

Abstract Surfactant loss due to adsorption on the porous medium of an oil reservoir is a major concern in enhanced oil recovery. Surfactant loss due to adsorption on the reservoir rock weakens the effectiveness of the injected surfactant in reducing oil–water interfacial tension (IFT) and making the process uneconomical. In this study, surfactant concentrations in the effluent of the corefloods and oil–water IFT were determined under different injection strategies. It was found that in an extended waterflood following a surfactant slug injection, surfactant desorbed in the water phase. This desorbed surfactant lasted for a long period of the waterflood. The concentration of the desorbed surfactant in the extended waterflood was very low but still an ultralow IFT was obtained by using a suitable alkali. Coreflood results show an additional recovery of 13.3% of the initial oil in place was obtained by the desorbed surfactant and alkali. Results indicate that by utilizing the desorbed surfactant during the extended waterflood operation the efficiency and economics of the surfactant flood can be improved significantly. Keywords Adsorption · Desorption · Surfactant · Interfacial tension · Enhanced oil recovery

1 Introduction The adsorbed surfactant layer on the porous media represents both an additional resistance to flow and loss of surfactant which are of importance in enhanced oil recovery (EOR). Surfactant adsorption during the flow of surfactant solutions through porous media is accompanied by a variety of complex phenomena. Surfactant adsorption governs the economic of chemical EOR (Gale and Sandvik 1973). Zaitoun and Berger (2003) studied the adsorption of surfactant in high salinity brine and divalent ions concentration. It can be considered as a partitioning of the adsorbate species between the interface and the bulk, and adsorption

S. B. Gogoi (B) Department of Petroleum Technology, Dibrugarh University, Dibrugarh 786004, India e-mail: [email protected]

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occurs if the interface is energetically favored by the surfactant in comparison to bulk solution (Paria and Khilar 2004; Zhang and Somasundaran 2006). The adsorption of surfactants can be affected by the surface charge on the rock and fluid interface (Leja 1982; Stumm and Morgan 1970). Positively charged cationic surfactant will be attracted to negatively charged surfaces and vis-a-vis. The surface charge of silica becomes negative when the pH increases above 2–3.7, while calcite does not become negative when the pH is greater than 8–9.5 (Somasundaran 1975; Stumm and Morgan 1970). Silica tends to adsorb cationic surfactants (Biswas and Chattoraj 1998), while calcite tends to adsorb anionic surfactants (Mohanty 2003). This occurs because silica has a negatively charged weak acidic surface in water near neutral pH, while calcite has a positively charged weak basic surface. The chemical reaction between the injected alkali and crude oil forms a surfactant that reduces the interfacial tension (IFT) which is dependent on the type and concentration of alkali and the chemical nature of oil (Trujillo 1983; Rudin and Wasan 1992; Surkalo 1990; Lui et al. 2008; Nasr-el-din and Taylor 1993; Touhami et al. 1998; Acevedo et al. 1999). Acid present in crude oil reacts with alkaline solution to produce in situ surfactant which lowers the IFT. The surfactant is surface active where it may form soap with sodium ions present in the aqueous phase at high ionic strength, which has a tendency to partition into the oil phase. In this article, the adsorption–desorption-related IFT phenomenon and its effect on EOR is studied. Experiments were conducted to obtain the adsorption–desorption behavior of surfactant on core samples during EOR of medium viscosity oil. The effects on oil–water IFT reduction by desorbed surfactant and alkali injections were investigated. The results of this article summarize that adsorption–desorption behavior of surfactant leads to an efficient and economical EOR process.

2 Materials and Methods 2.1 Materials The porous medium was the core sample from the producing horizon of Naharkotiya oil field of Deohal in Upper Assam Basin from a depth of 3856–3859 m. Sodium lignosulfonate (SL) and chloroform were supplied from Merck Specialities Pvt. Ltd., Kolkata. SL is an anionic surfactant with a molecular weight of 535 g/mol, chemical formula of C20 H24 Na2 O10 S2 with the hydrophilic group carrying a negative charge such as sulfonate. SLs are by-product of sulfite cellulose pulp production, they contain hydrophilic groups which make them water soluble (Dawy et al. 1998; Telysheva et al. 2001; Wang 2002). They can be described as anionic surfactants, which are relatively low cost and are widely used in many applications (Li et al. 2007; Matsushita et al. 2005; Pei et al. 2008; Gogoi 2009). Studies have shown that aqueous solution of SL could reduce the IFT between oil and water thereby releasing the captured oil blobs from the porous media (Son et al. 1982; Hornof et al. 1982; Babu et al. 1984; Gogoi 2010). Analytical grade sodium hydroxide (NaOH) was supplied by BDH, Mumbai, India. The paraffin oil of viscosity (µo ) 0.56 mPa s and density (ρo ) 810 Kg/m3 was collected from Digboi Refinery. The brine solution was 3000 ppm of NaCl in distilled water (DW) having viscosity (µw ) of 0.97 mPa s and density (ρw ) of 1000 kg/m3 . Catflo-T (Cationic Polyelectrolyte) a deoiler and a mixed indicator (Methyl Red–Methylene Blue) were supplied by Thermax, Puna.

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2.2 Methods 2.2.1 Measurement of Surfactant Concentration and IFT The two phase titration was done by agitating desired amounts of solids i.e., the core sample (5–20 g) with the required volume of surfactant solution for a known time in pyrex vials, partially placed in an incubator maintained at 40◦ C. At the end of the test, a sample of the supernatant solution was centrifuged at 1500 G (gyrations) for 20 min. The liquid above the mineral layer was thoroughly mixed with the supernatant and analyzed for residual sulfonate concentration. From the difference of the initial and final values, the adsorbed surfactant was calculated. Samples for the determination of residual concentration were taken, in this case from the upper region of the supernatant. The concentrations of surfactant were determined by using the two-phase titration method with a mixed indicator (ASTM D 3049 1989; Power 1970; Reid et al. 1967). As the density of SL (1090 kg/m3 ) (Gogoi 2008) was less than chloroform (1483 kg/m3 ),the upper phase was SL and the lower oleic phase was chloroform in the collecting test tube. The chloroform layer appears red in the presence of excess of anionic surfactant and blue with excess of cationic titrant. The end point was greenish-blue which coincides with the complete transfer of a small quantity of methylene blue (cationic) to the chloroform layer. The titration procedure was as follows: 1. 2.

3.

Added 2 ml of SL solution, 25 ml of water, 15 ml of chloroform, and 10 ml of mixed indicator solution in a mixing cylinder. Added 0.004 mol/l of deoiler in the mixing cylinder and shaken vigorously for 1 min. The cylinder was allowed to stand until the emulsion breaks and the two phases appear. The lower layer appears red at this stage. Titration was continued and vigorously shaken for each addition of titrant for 15 s near the end point; titration was continued with dropwise addition of titrant and shaken within additions, until the end point was reached. The volume of titrant added was recorded. The IFT was determined using Spinning Drop Tensiometer at room temp of 21 ± 3◦ C.

2.2.2 Surfactant Adsorption and Desorption Tests 2.3.2.1 Preparation of Cores The surfactant adsorption–desorption tests were performed in cores with air permeability of 81.62–98.72 md (86.14 md was taken for calculation) and effective porosity of 18.78–21.90% (20.34% was taken for calculation). The cores were 5.0 cm in length and 2.5 cm in diameter. After the cleaned cores were dried for 24 h at 100◦ C, two distributors were attached to the core plug; these were covered with two ends connected with the injection and production line, respectively as in Fig. 1. The core was vacuumed to a pressure of 133.32 × 10−5 Pa. The 3000 ppm brine was imbibed to saturate the core. The core was then ready for the adsorption–desorption and coreflood test. Brine concentration of 3000 ppm was taken to match with the formation water brine concentration of Nahorkatiya reservoir. 2.3.2.2 Adsorption–Desorption Tests Solution containing 0.2 wt% surfactant and 1.0 wt% NaOH in 3000 ppm brine was continuously injected into the core until the effluent surfactant concentration of the solution approached that of the injected surfactant concentration of the solution. The effluent surfactant concentrations were analyzed by 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 of surfactant in the effluent samples.

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Injection line

Production line

Coating of resin

Fig. 1 Coreflood for adsorption and oil recovery tests

To characterize the adsorption–desorption behavior of the surfactant at an injection rate of 0.0042 cc/s, 1.5 PV1 of alkali–surfactant (A/S)2 solution was injected followed by continuous brine injection. The effluent samples were analyzed for alkali and surfactant concentrations. IFT between the effluent solution and oil was measured. 2.3.2.3 Coreflood Tests In this test, the IFT reductions as a result of desorption of surfactant during the extended waterflood and its effect on oil recovery are studied. Oil was injected to the brine saturated core till irreducible water saturation (Swi ). Then the core was flooded with brine till the residual oil saturation (Sor ). Then 1.5 PV of the A/S slug was injected, followed by 1 PV of alkali (A) injection or by extended water flood. For each set of coreflood tests, the runs were of A injection and of extended water flood i.e., brine flood. In both the cases the oil recovery was measured. The oil and the aqueous phase in the effluent samples were separated by adding two drops of the deoiler and vigorously shaken and allowed to settle for 24 h in test tubes. The surfactant and alkali in the aqueous phase of the samples were analyzed. The IFTs between the effluent aqueous sample and oil were measured.

3 Results and Discussion 3.1 Adsorption Test Equilibrium adsorption of surfactant in core was measured by a continuous injection method. Figure 2 shows the normalized surfactant concentration in the effluent samples as a function of the PV of produced fluid. The normalized surfactant concentration (NSC) in terms of surfactant concentration was obtained as follows: SCE NSC = , SCI where SCE is surfactant conc. in the effluent sample and SCI the surfactant conc. in the injected sample. The NSC reached adsorption maxima at 0.913 and 22 PV fluid productions, which remained constant till it reached 32 PV i.e., for another 10 PV. An equilibrium monolayer adsorption had reached and that the continued loss of surfactant after 22 PV was the result of multi layer adsorption. The test was stopped at 32 PV productions. 1 PV: PV is the pore volume which is the difference between the bulk volume (cc) and grain volume (cc) of

the core sample (Core Analysis, 1998). 2 (A/S): A/S is alkali–surfactant which is 0.2 wt% surfactant and 1.0 wt% NaOH in 3000 ppm of brine solution.

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Fig. 2 Normalized surfactant concentration versus PV of fluid produced in the equilibrium adsorption test

As shown in Fig. 2 and in several other experimental studies (Levitz and Damme 1986; Levitz 2002; Denoyel et al. 1983; Denoyel and Rouquerol 1991), all adsorption isotherms reach a plateau around the critical micelle concentration (CMC), independent of any concentration used above the CMC. This plateau decreases when the polar chain length increases. The amount of surfactant adsorbed was obtained as follows: Surfactant adsorbed = Surfactant injected − Surfactant in the effluent. High energy surfaces (clays, fines etc.) adsorb surfactants. It can be assumed that solids are negatively charged in water, ion exchange of sodium (or other monovalent) cation would control the adsorption of the surfactant by bringing the negatively charged sulfonate ion into the molecular layers surrounding the solids. On the other hand, Van der Waal’s and hydrogen bonding forces can cause the negatively charged sulfonate molecules to be adsorbed directly on the solids (Holm 1977). The adsorption of surfactant in the core under the test condition was found to be 2.3 × 10−6 mol/g core(2.3 µmol/g). This amount of adsorption appeared reasonable since Trogus et al. (1977) experimentally determined an equilibrium adsorption of sodium dodecyl benzene sulfonate on Berea core to be 2.0 µmol/g. The permeability test of Nahorkatiya core sample of 5 cm length (L) and 2.5 cm diameter (D) was conducted and operated vertically in the liquid permeameter. Flooding solutions were injected by self-priming monoblock 0.25 HP pump. The inlet and outlet pressure of the cylindrical section was recorded from pressure gauges. Experiments were conducted at room temperature of 28 ± 2◦ C. Calculating the permeability to brine (K ) which was 86.14 md, the flow rate was measured through the porous media with and without surfactant (both with and without adsorption considered). A = Area of the porous media =

π D2 = 4

22 7

× (2.5)2 = 4.911 cm2 4

Calculation of flow rate with surfactant i.e., with adsorption K ∗ P ∗ A µ0 ∗ L 86.14 md ∗ 0.87 atm ∗ 4.911 cm2 Q= 0.56 cp ∗ 5 cm

Q=

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Q = 131.443 cc/s Calculation of flow rate without surfactant i.e., without adsorption K ∗ P ∗ A µ0 ∗ L 86.14 md ∗ 1 atm ∗ 4.911 cm2 Q= 0.56 cp ∗ 5 cm Q = 151.083 cc/s.

Q=

From the above calculations, it appears that the flow rate with surfactant (i.e., with adsorption) was lower than that without surfactant (i.e., without adsorption), this is because during adsorption of surfactant, it gets adsorbed to the pore walls of the porous medium and obstructs the flow of fluid, thereby reducing the flow rate. 3.2 Adsorption–Desorption Tests In order to simulate the adsorption–desorption process, alkaline–surfactant (A/S) solution of 1.5 PV was injected in the core sample where both the surfactant and alkaline concentrations in the effluent samples were determined during the chemical slug injection and the extended brine or waterflood process. The surfactant slug was used to recover crude oil from the porous medium after water flooding. The water soluble surfactant will reduce the IFT between the oleic and the aqueous phase, thereby releasing the trapped oil from the porous medium. A portion of the surfactant will also get adsorbed on the porous medium, so to desorb the surfactant alkali was used. A/S flooding is already an established technique in conventional oil reservoirs, whereby EOR is a result of reduced trapping of oil due to the lowered oil/water IFT. In addition, the injection of these chemicals may lead to the formation of emulsions. In this study, it is demonstrated that in oil systems, emulsion formation is a necessary requirement for the production of oil. When these emulsions form, A/S injection can lead to considerable improvements in the flooding response (Bryan and Kantzas 2007). The dominant mass-transfer mechanisms in the porous medium include diffusion through the fluid film around the particle and diffusion through the pores to internal adsorption sites. The actual process of physical adsorption is practically instantaneous, and equilibrium is assumed to exist between the surface and the fluid at each point inside the particle ( McCabe et al. 1993). Figure 3 shows the NSC and alkali concentrations in the effluent samples as a function of produced fluid in PV. The NSC reached a maximum of 0.14 at 3.2 PV of produced fluid and then decreases slowly till it reaches 0.03 at 16.2 PV of fluid produced at the outlet of the core sample during A/S flooding. The total surfactant injected was 0.2 wt% and the surfactant obtained in the effluent was 0.078 wt%, therefore from mass balance the amount of surfactant in the effluent was 39% of the total surfactant injected in 24 PV of solution (When injected surfactant was 0.2 wt%, the surfactant in the effluent was 0.078 wt%. Therefore, when injected surfactant was 100%, the surfactant in the effluent was 39% and the alkali in the effluent was 61%). The maximum normalized alkaline concentration was 0.78 in 2.5 PV of produced fluid at the outlet of the core sample during A/S flooding. The residual adsorption of the surfactant was 0.21 µmol/g which was equivalent to 9.13% of the adsorption determined in the adsorption test. The monovalent sodium ion from brine appears to enhance adsorption of the sulfonate by acting as counter ions and possibly by salting out effects.

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Fig. 3 Normalized surfactant and NaOH concentration versus PV of fluid produced in alkaline/surfactant slug injection test

In contrast to this, anions are seen to compete with the sulfonate groups of the surfactant and decrease its adsorption on core sample. The effect of anions was found to increase in − the order Cl− < SO2− 4 < phosphate (mostly in HPO4 form in the pH region under consideration) (Hanna and Somasundaran 1977). Seethepalli et al. 2004 proposed that anionic surfactants would change the wettability of the calcite surface to intermediate/water-wet condition as well or better than the cationic surfactant. The surfactant concentration curve is compared to the NaOH concentration curve w.r.t. PV of liquid produced. The surfactant concentration peak appears after NaOH concentration peak as in Fig. 3. The normalized alkali concentration decreased from 0.78 to 0.035 wt% rapidly in 5 PV of production. After 16.2 PV of production, the NaOH concentration in the effluent decreased to 0.015 wt% as compared to the original NaOH concentration of 1.0 wt%. The major reason of delay of the small amount of alkali production is due to the molecular diffusion and dispersion at the rear end of the A/S slug. The systematical curve of NaOH suggests that there was no retention of NaOH due to dead end pore volume in the core (Green and Willhite 1998). After the maximum point, the normalized surfactant concentration decreased from 0.14 to 0.03 in 15.9 PV of production. When NaOH concentration in the effluent reached its maximum, the surfactant concentration was still increasing. This indicated that the separation of surfactant from A/S slug occurred by adsorption first and then by desorption during the flow through the core. The long lasting surfactant concentration curve results from desorption of the surfactant from the solid surface to the water phase. When the chemical slug flows through the core sample, 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 IFT and improving oil recovery. 3.3 IFT Behavior The IFT between the effluent sample and oil was measured to find the effect of desorbed surfactant on reducing the IFT. The results are shown in Fig. 4; the NaOH curve is a part of the curve from Fig. 3 corresponding to 2.5–16.2 PV of PV produced. Table 1 and Fig. 4

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0.8 6

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wt % of NaOH in PV of effluent brine produced

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PV of effluent brine produced

Fig. 4 IFTs between effluent brine and oil in 2.5 PV A/S slug injection test Table 1 Results of IFT showing the decrease of IFT with the increase of wt% NaOH in PV of effluent produced

wt% NaOH

PV of effluent brine produced

IFT in dyne/cm

0.015 0.018 0.019 0.02 0.03 0.035 0.1 0.18 0.28 0.43 0.78

16.2 14 10 9 8 7.5 6.5 5.5 4.5 3.5 2.5

7.45 7.4 7.2 7.3 7.4 7.6 7 5 3.7 2 0.8

shows the decrease of IFT with the increase of wt% NaOH in PV of effluent produced during the core flood experiment. In the first sample, NaOH concentration was about 0.78 wt% and IFT was 0.8 dyne/cm. As we proceed from right to left along the IFT and NaOH curve in Fig. 4, we see that with the increase of NaOH in the effluent brine there is a decrease in IFT. Experimental investigations for oil–brine system showed that adding alkali to the surfactant solution helped to reduce oil/water IFT (Huang and Dong 2002) as in Fig. 5. These observations were in agreement with that the minerals in the core sample which will become increasingly negatively charged with an increase in pH by addition of NaOH and possibly retard the adsorption of an anionic surfactant such as SL (Hanna and Somasundaran 1977). 3.4 Oil Recovery by Desorbed Surfactant in Extended Waterflood The test was conducted to assess the effect of the desorbed surfactant and alkali concentration on oil recovery in the extended water flood. Two corefloods were carried out for comparison, the details of which are in Table 2. Figures 5 and 6 show the cumulative oil recovery versus pore volumes produced of sets 1 and 2, respectively. In each set of tests, initial waterflood oil recoveries of the two runs (with alkali and without alkali 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 by adding alkali in the extended waterflood.

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Table 2 Details of coreflood tests Experimental

Coreflood (PV)

A/S slug

A slug Recovery (% IOIP)

Set 1

Waterflood A/S slug A slug Extended waterflood Injection rate (cc/s) A conc. (wt%) S conc. (wt%) Injection rate (cc/s) A conc. (wt%) Waterflood A/S slug A slug Extended waterflood Total

Set 2

Run 1

Run 2

Run 3

Run 4

5.0 2.5 − 5.0 0.0042 1.0 0.1 0.0042 − 23.4 21.3 − 10.4 55.1

5.0 2.5 5.0 − 0.0042 1.0 0.1 0.0042 1.0 23.4 22.5 22.5 − 68.4

4.0 1.5 − 4.5 0.0028 0.5 0.1 0.0028 − 20.6 14.5 − 7.0 42.1

4.0 1.5 4.5 − 0.0028 0.5 0.1 0.0028 − 20.8 14.8 12.0 − 47.6

Fig. 5 Oil recovery curves of the first set of coreflood tests

In Set 1 tests shown in Fig. 7, the waterflood of both runs recovered 23.4% of initial oil in place (IOIP). In Run 1, A/S slug and extended waterflood together recovered 31.7% IOIP (21.3% + 10.4% = 31.7%), and total oil recovery was 55.1% IOIP. In Run 2, A/S and alkaline slug together recovered 45% IOIP (22.5% + 22.5% = 45%), and the total recovery was 68.4% IOIP. The NaOH concentration in the extended waterflood of Run 2 was 1.0%. The incremental oil recovery by Run 2 (A/S + A) slug was 13.3% IOIP more than Run 1. In Set 2 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 20.8% IOIP which was slightly lower than for the Set 1. The initial A/S slug and extended waterflood injected recovered 21.5% IOIP (14.5% + 7.0% = 21.5%) for each of the two runs, which is much lower than the recovery obtained in Run 1 (21.3% + 10.4% = 31.7%

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Fig. 6 Oil recovery curves of the second set of coreflood tests

Fig. 7 NaOH concentrations in effluent samples for Set-1 coreflood tests

IOIP) of Set 1. Low alkali and surfactant concentration rate are the two major reasons for low oil recoveries in Set 2 and the extended waterflood of Run 4. The effect of alkaline on oil recovery in actual reservoir condition is due to the chemical reactions between the alkaline and organic acids occurring in the crude. These reactions result in the formation of surface-active compounds whose adsorption on oil–water interfaces decreases the IFT between oil and water, as one of the oil recovery mechanisms of alkaline flooding thus yielding an oil–water emulsion (Mihcakan and Van Kirk 1988). 3.5 Analysis of Interaction in Desorbed Surfactant/Alkali/Oil Systems Several effluent samples were collected from each coreflood tests. The oil was separated from water by Catflo-T (Cationic Polyelectrolyte) a deoiler. Chemical analysis was done in both oil and water phase. Oil–water IFTs were determined by Spinning Drop Tensiometer at

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Fig. 8 NaOH concentrations in effluent samples for Set-2 coreflood tests 100

Run 2, A/S+A, Equilibrium oil Run 2, A/S+A, Original oil

IFT, dyne/cm

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Run 1, A/S, 1%A, Equilibrium oil

0.1

Run 1, A/S, 1%A, Original oil

0.01 4

5

6

7

8

9

Pore volume produced

Fig. 9 IFT curves for oil (produced and original oil) and the effluent water samples of Set-1 coreflood tests. NaOH (1.0 wt%) was added to the effluent water samples of Run 1

room temp of 25◦ C. The alkali concentrations of the effluent water samples were measured by titration for two sets of coreflood experiments. The results are shown in Figs. 6 and 7 for Sets 1 and 2, respectively. The NaOH concentration decreased after 7.5 and 7 PV produced in the A/S injection runs in Figs. 7 and 8, respectively, while it continued to increase in A/S + A injection runs in both Figs. 8 and 9. In coreflood experiments with surfactant it was found that surfactant was retained initially, but was released during the extended waterflood and A slug injection (Table 2) following A/S slug injection. On the otherhand, Krumrine et al. (1982) also observed this phenomenon with petroleum sulfonate and Berea core, during saline postflush following sodium carbonate. It is seen that addition of NaOH in the extended waterflood improved oil recovery in both Figs. 8 and 9 by the following mechanisms: Reduction of I F T The reaction between surfactant and NaOH in solution creates a surface active agent which helps in the reduction of IFT. Trujillo (1983) studied the reaction between surfactant and NaOH solution that reduces the IFT. A novel methodology for isolation of native petroleum surfactants for lowering IFTs in aqueous-alkaline systems was explained by Yen and Farmanian (1980). They explained the petroleum synthesis with the capability

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Run 3, A/S, 0.5%A, Original oil 0.01 3

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Pore volume produced Fig. 10 IFT curves for oil (produced and original oil) and the effluent water samples of Set-1 coreflood tests. NaOH (0.5 wt%) was added to the effluent water samples of Run 3

of surface tension reduction at high pH values. Due to addition of alkali, the pH raises which results in the saponification of naphthenic acids in crude oil to naphthenic soap, a natural surfactant, which helps to lower the IFT (Hirasaki et al. 2006). Alteration of wettability Leach et al. (1962) concluded that NaOH can effectively change rock surfaces from oil-wet to water-wet. Oil wetting surfaces lead to poor oil displacement, whereas water-wetting surfaces lead to efficient oil displacement. It was observed (Moore and Slobod 1956) that oil recovery in water breakthrough in water-wet systems is much higher than oil-wet systems. It has been reported (Morrow et al. 1973) that polar constituents in crude oil play an important role in determining the reservoir wettability due to their adsorption on rock surfaces. The effect of wettability on the efficiency of oil displacement during surfactant flooding has been reported (Kremesec and Treiber 1987). Wettability is a function of solid–liquid and liquid–liquid interface. To investigate the adsorption–desorption-related IFT behavior in the extended waterflood, water–oil IFT was measured for the following different types: 1. 2. 3. 4.

Effluent samples for the two A/S + A runs (Runs 2 and 4). Original oil and the effluent water samples for the two A/S + A runs (Runs 2 and 4). Effluent samples for the two A/S runs (Runs 1 and 3). However 1 and 0.5% NaOH was added to the effluent water samples of Runs 1 and 3, respectively. Effluent water samples for the two A/S run (Runs 1 and 3). Similarly NaOH was added to the effluent as in no. 3 above.

The measured IFT results of the first and second coreflood tests are shown in Figs. 10 and 11, respectively. In each figure four types of curves which correspond to Table 1 are presented. Figures 10 and 11 show a similar variation at different condition (equilibrium oil vs. fresh oil, equilibrium oil vs. water with fresh NaOH). For all the curves of Figs. 9 and 10, NaOH used was 1.0 and 0.5 wt%, respectively. The oil–water IFT reached a minimum when 1.0 wt% NaOH (Fig. 9) was used than using 0.5 wt% NaOH (Fig. 10). Therefore, the discussion will be for Fig. 9. The L shaped curves of Fig. 9 which correspond to type 1 shows that low IFT between equilibrium oil and water (∼2 dyne/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.

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0.3

Run 1, A/S

0.2

Run 2, A/S+A 0.1

0 0

2

4

6

8

10

Pore volume produced

Fig. 11 Surfactant concentration in the effluent samples of Set-1 coreflood tests

In Fig. 9, the IFTs of the effluent water-original oil systems (type 2) were several times lower than those of the effluent brine-produced oil systems (type 1). In the type 1 system, the oil and water reached equilibrium quickly as there was no more reaction and partition across the oil–water interface. When original oil was contacted with produced water sample, which contained both surfactant and alkali, both reaction between the alkali in the water and acid in the oil and mass transfer across the oil–water interface occurred during the IFT measurement. It is because of these processes there occurs much lowering of the IFT with time very slowly. The two V-shaped curves of Fig. 9 are IFTs between the oil (produced and original) and effluent water sample of Run 1. In this run, an A/S slug was followed by an extended waterflood without alkali. 1.0 wt% NaOH was added to the effluent water samples, which contains some desorbed surfactant to assess its effect on the IFT. It was observed in Fig. 9 that IFTs of some samples were reduced to 0.02 dyne/cm. In Fig. 4, the IFTs of the effluent water samples (no alkali) with original oil were higher than 7.5 dyne/cm. From this result, it is speculated that in coreflood Run 2 the low IFTs were obtained during the alkali slug injection. The low IFTs result from interaction between NaOH and oil and between the alkali and desorbed surfactant. The results of the four coreflood tests are shown in Figs. 11 and 12. It is seen that the surfactant concentration in the effluent samples of A/S + A Run were lower than those of A/S Run. The introduction of A into the brine-surfactant-rock system increased the salinity of the water phase and depressed the liquid–liquid and solid–liquid interface double layers. This caused more adsorption of surfactant at oil–water interfaces and partitioning of surfactant into the oil phase. These processes occurred during the coreflood which resulted in low IFT and displacement of more oil from the core samples.

4 Conclusion Adsorption of A/S solution occurs in the Naharkotiya core sample first then part of it was desorbed during the extended water flooding after the A/S slug injection. Experimental results indicate the presence of both the desorbed surfactant and NaOH in the extended waterflood reduces oil–water interfacial tension thereby releasing the trapped oil from the core sample. When the interfacial tension was measured between fresh alkaline solutions, including

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602 0.3

Run 3, A/S 0.2

Run 4, A/S+A

0.1

0 0

1

2

3

4

5

6

7

8

Pore volume produced

Fig. 12 Surfactant concentration in the effluent samples of Set-2 coreflood tests

desorbed surfactant and oil, low interfacial tension was obtained. The result of this low interfacial tension is due to the desorbed surfactant and NaOH in the extended waterflood. Core tests were carried out to examine the role of desorbed surfactant and alkali concentration in enhancing oil recovery during extended waterfloods. It was observed that additional oil was recovered when desorbed surfactant and NaOH was flooded during the extended waterflood. Acknowledgments I would like to express my sincere thanks to Dr. N.N. Dutta of NEIST, Jorhat, Assam for his sincere guidance in completing the study.

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