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Combined Surfactant-Enhanced Gravity Drainage (SEGD) of Oil and the Wettability Alteration in Carbonates: The Effect of Rock Permeability and Interfacial Tension (IFT) Reza Rostami Ravari,* Skule Strand, and Tor Austad Department of Petroleum Engineering, Faculty of Science and Technology, University of Stavanger, 4036 Stavanger, Norway ABSTRACT: Water-based enhanced oil recovery from fractured oil-wet or mixed-wet carbonate rock by water flooding is a great challenge. Surfactant-assisted wettability alteration in combination with the impact of gravity drainage appeared to be one possible technique. The big challenge is to select a surfactant system, which is able to cause wettability modification, and, at the same time, to keep the interfacial tension (IFT) between oil and water high enough to take benefit of capillary forces and low enough to activate gravity forces in the oil displacement process. Furthermore, the surfactant should not adsorb onto the rock, which could decrease the water-wetness. Cationic surfactants of the type alkyltrimethylammonium, RN(CH3)3þ, have the properties needed, IFT in the range of 0.11.0 mN/m, not affected by salts, and no adsorption onto the rock. Phase trapping because of complex formation between the cationic surfactant and carboxylic material in the crude oil is a possible way for the loss of chemicals, especially at low temperatures. They act as good wettability modifiers in the presence of sulfate, even at low temperatures. Spontaneous imbibition experiments have been performed at 50 °C in oil-wet reservoir limestone cores of quite different permeability (0.46 and 364 mD), and the results were discussed in terms of a previous study in chalk. For the high-permeable core, different impact of capillary and gravity forces resulted in different flow regimes with respect to the imbibing time: (1) capillary forces (≈30% recovery), (2) combined capillary and gravity forces (recovery increased to ≈40%), (3) gravity forces [ultimate recovery of 5060% of original oil in place (OOIP)]. The fraction of oil recovered by gravity forces increased as the IFT decreased from 0.67 to 0.34 mN/m. No oil was recovered from the low-permeable core, indicating that the rock permeability is a very important parameter when judging the efficiency of the process. The time scale for a diffusion process is linked to the square of the length scale of the medium. The time required to achieve 70% of the recoverable oil from the core plug in the laboratory was 1 day. Applying the upscaling equation, the corresponding time required to achieve 70% of the recoverable oil from a 1 m3 reservoir block would be in the order of 2 years. Consequently, a combined effect of surfactant-enhanced gravity drainage (SEGD) and the wettability alteration in fractured, highpermeable, oil-wet carbonate rock can provide an economically interesting opportunity.
’ INTRODUCTION Oil recovery from fractured oil-wet or mixed-wet carbonate rock by water flooding is a great challenge. Most of the injected water will pass through the fracture network without displacing oil present in the matrix blocks. Therefore, to apply water-based enhanced oil recovery (EOR), the injected water must be able to alter the rock wettability toward more water-wet conditions. Capillary forces are then activated, and oil will be displaced from the matrix blocks by a spontaneous imbibition process. At high temperatures, T > 90100 °C, we have shown that seawater may act as a “smart EOR fluid”, which is able to change wetting properties of carbonate rock and improve oil recovery drastically both in a spontaneous imbibition process as well as by forced imbibition.13 The chemical mechanism has been described by a symbiotic interaction between potential determining ions in seawater (Ca2þ, Mg2þ, and SO42) and the carbonate surface.4 Especially, the presence of sulfate appeared to be very important, and the wettability alteration process could even take place at lower temperatures by spiking the seawater with sulfate.1 At low temperatures, surfactants present in the injection water can impose a combination of gravity drainage and wettability alteration. Under such conditions, both gravity and capillary forces will be active in the oil displacement from the matrix blocks. We have previously shown that cationic surfactants of the type r 2011 American Chemical Society
alkyltrimethylammonium bromide, RN(CH3)3Br (CnTAB), alkylamine, C10NH3Cl, and bioderivatives from the coconut palm, called Arquard and Dodigen, can both act as wettability modifiers in chalk,5 limestone,6 and dolomite.7 The decrease in the interfacial tension (IFT) between the injected surfactant solution and the oil was moderate, showing values in the range of 0.11.0 mN/m. Spontaneous imbibition experiments using chalk cores of different heights (530 cm) showed that all of the tested parameters scaled surprisingly well by just using the height of the core as the shape factor in the expression of dimensionless time, td, indicating that gravity forces were quite active in the oil displacement.8 Later, experimental studies in low-permeable chalk, 13 mD, were performed using a special designed imbibition cell to separate the oil recovery from the top surface and the rest of the core surface.9 The oil recovery rate per surface area unit (day1 cm2) from the top and the rest of the core surface was calculated and plotted against the imbibition time. The tests were performed on preferentially oil-wet cores with a water-wet area fraction of 0.37, without initial formation water present. The acid number of the crude oil was high, 1.7 mg of KOH/g. C12TAB dissolved in Received: January 16, 2011 Revised: April 19, 2011 Published: April 19, 2011 2083
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Figure 3. Fractional oil recovery rate per unit area for the core E5b from the top surface and the rest of the surface area. T, 40 °C; h, 2.67 cm; IFT, 1.1 mN/m.9 Figure 1. Recovery curves of the imbibition with 3.5 wt % C12TAB. T, 40 °C; Swi, 0; IFT, 1.10 mN/m. The height of core 5a was 5.0 cm, and the height of core 5b was 2.67 cm.9
Figure 2. Fractional oil recovery rate per unit area for the core E5a from the top surface and the rest of the surface area. T, 40 °C; h, 5.0 cm; IFT, 1.1 mN/m.9
seawater was used as the imbibing fluid at 40 °C, and the IFT was 1.1 mN/m. The oil recovery rate per area unit from the top surface and the rest of the core was quite different against the imbibition time. At the start, the oil recovery rate from the side and bottom surfaces was significantly higher than that from the top surface. Later, the oil recovery rate from the top surface was increased and became much higher than that from the other surfaces (Figures 1 and 2). As the height of the core decreased from about 5.0 to 2.62 cm, the relative amount of oil produced from the top surface decreased; i.e., the impact of gravity forces on oil recovery decreased (Figure 3). The impact of gravity forces became even more significant as the IFT of the surfactant solution was decreased from 1.1 to 0.63 mN/m (Figure 4). The oil recovery rate per unit area from the top surface was much higher than that from the rest of the core surfaces, even from the start of the imbibition process. Thus, the test clearly demonstrated the impact of both gravity and capillary forces, because of wettability alteration, in the imbibition process. Diffusion of the surfactant into the porous medium will play an important role in this process. In the lab experiments, the diffusion rate of the surfactant will probably not be the ratedetermining step in the process. In field situations, however, diffusion of the surfactant into the porous medium may be the rate-determining factor for oil displacement. Upscaled simulations performed by Stoll et al.10 using a cationic surfactant in lowpermeable chalk showed that, for a 1 m3 matrix block, it would take about 200 years for full penetration of the imbibing fluid. It must be mentioned that the upscaling was performed by neglecting the impact of gravity forces.
Figure 4. Fractional oil recovery rate per unit area for the core M3 from the top surface and the rest of the surface area. T, 40 °C; h, 5.0 cm; IFT, 0.63 mN/m.9
Masalmeh and Oedai11 investigated the impact of initial water saturation on the process of surfactant-enhanced gravity drainage (SEGD) in carbonates. From experimental tests using a centrifuge, they concluded that initial water showed little or no impact on the measured surfactant wateroil Pc curves. They also concluded that molecular diffusion of surfactant alone could not explain the rate and volume of oil recovered by the SEGD process. Mohanty and co-workers12 have performed extensive studies, both experimental and numerical simulations, on upscaling of oil recovery from fractured carbonates by surfactant-aided gravity drainage. They used anionic surfactants dissolved in an optimum salt solution of Na2CO3 to give low IFT of about 102 mN/m and to reduce the adsorption of surfactant onto the carbonate surface. Injection of a solution of Na2CO3 into a fractured carbonate reservoir containing a high concentration of Ca2þ in the formation water is, however, questionable because of precipitation of CaCO3 in the mixing zone and possible decrease in permeability. They observed a decrease in the oil recovery rate as the permeability of the rock decreased, which was scaled by gravitational dimensionless time, indicating a process governed by gravity forces. Furthermore, at the field scale, it was modeled that 50% of recoverable oil could be recovered in about 3 years with a fracture spacing of 1 m. Thus, by knowing optimum conditions for the SEGD process in naturally fractured carbonates, it should be possible to recover a significant amount of recoverable oil within a reasonable time frame. In the present paper, the SEGD process is studied using two different cationic surfactants, which are able to act as wettability modifiers and, at the same time, give a moderate decrease in IFT, 0.34 and 0.67 mN/m. Under those conditions, the fluid flow during the oil displacement process will be determined by both 2084
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Table 1. Selected Properties of the Crude Oil Sample ANa
BNb
density
viscosity at
crude oil
(mg of KOH/g)
(mg of KOH/g)
(g/cm3)
22 °C (cP)
RES40-0.57
0.57
0.25
0.8012
3.1
Table 3. Core Properties L (cm)
D (cm)
porosity (%)
k (mD)
Swi (%)
Res 52
4.77
3.73
28
364
10
Res 4-12
4.80
3.79
16
0.46
10
core number
a
The AN was determined according to the modified version of ASTM D-664.21 b The base number (BN) was determined according to the modified version of ASTM D-2896.21
Table 4. IFT Measurement at 50 °C surfactant
Table 2. Brine Composition ions
FW (mol/L)
SW (mol/L)
HCO3
0.009
0.002
Cl
1.066
0.525
SO42
0.000
0.024
Mg2þ
0.008
0.045
Ca2þ
0.029
0.013
Naþ
0.997
0.450
Kþ
0.005
TDS (g/L) IS (mol/L)
62.83 1.112
0.010 33.39 0.66
capillary and gravity forces. The test will be performed on two limestone cores of quite different permeability, 0.46 and 364 mD, and the results will be discussed in relation to our previous study on 13 mD chalk using a similar type of surfactant.9 Thus, the objective is to study the effect of rock permeability on the oil displacement process at two different IFT values, which are still high enough to activate capillary forces.
’ EXPERIMENTAL SECTION Oil. A crude oil with a high acid number (AN = 1.84 mg of KOH/g) was made by diluting a high acidic North Sea crude oil with heptane in a volume ratio of 40:60 heptane/crude. A fraction of the same oil was treated with silica gel to obtain an oil with a very low AN (AN = 0.02 mg of KOH/g). Then, the oil with an AN = 0.57 mg of KOH/g was made by mixing the high and low AN oils in a proper ratio. The oil was filtered through a 5 μm Millipore filter. No precipitation of asphaltenes was observed after diluting with heptane and during the storage. Chemical and physical properties of the oil are listed in Table 1. Brines. The composition of the brines used is listed in Table 2. Synthetic seawater (SW) was doped with 1.0 wt % C12TAB and 0.5 wt % Dodigen in the imbibition tests. Both brines were filtered through a 0.22 μm Millipore filter and vacuumed to remove dissolved gas prior to use. Surfactants. The cationic surfactant C12N(CH3)3Br, termed C12TAB, was obtained from Sigma and used without further purification. Dodigen 5462 containing approximately 50% C12N(CH3)3Cl, 24% C14N(CH3)3Cl, 11% C16N(CH3)3Cl, and 13% C18N(CH3)3Cl was obtained from Hoechst AG, Germany, and was used without further purification. Core Material. The experimental study was performed on two different reservoir limestone cores. The permeability and porosity of core Res 52 was 364 mD and 28%, while the corresponding values for the low-permeable core were 0.46 mD and 16%, respectively (Table 3). Core Preparation. The cores were cleaned by flooding the cores at room temperature with water-saturated toluene until the effluent became colorless.13 Thereafter, the cores were flooded with several pore volumes (PVs) of methanol to remove toluene. The cores were also flooded with SW þ 1.0 wt % C12TAB at 130 °C at a rate of 3 PV/day for 3 days.14 Finally, the cores were flooded with deionized (DI) water to remove
oil
brine
surfactant
concentration (wt %)
IFT (mN/m)
RES40-0.57
SW
C12TAB
1.0
0.67 ( 0.03
RES40-0.57
SW
Dodigen
0.5
0.34 ( 0.03
surfactant and salt, and the effluent was checked for SO42. As sulfate adsorbs onto the rock, it is more difficult to displace; therefore, the core was flooded with DI water until the effluent was free from sulfate, as tested using BaCl2. The cores were dried to a constant weight at 90 °C. Initial Water Saturation (Swi). The dried cores were saturated with 10 times diluted formation water, under vacuum, and the initial water saturation of 10% was established using a desiccator.15 Oil Saturation and Aging. The cores were saturated and flooded by RES40-0.57, 2 PVs in each direction, and finally aged at 90 °C for 2 weeks. The cores were wrapped in Teflon tape to avoid unrepresentative adsorption of polar components onto the surface during the aging process.16 Spontaneous Imbibition. The spontaneous imbibition tests were performed at 50 °C using Amott cells. The oil recovery, calculated as the percentage of original oil in place (OOIP), was recorded versus time. IFT. The IFT measurements were performed using a Kruss SITE04 spinning drop tensiometer with a small sample volume set installed. The IFT measurements between the crude oil and the surfactant solutions were performed at 50 °C, and the value reported in Table 4 is the average of at least three measurements.
’ RESULTS AND DISCUSSION Cationic surfactants do not adsorb onto the positively charged carbonate rock. Thus, the loss of surfactant because of adsorption is negligible, provided that the formation is not contaminated by silica. The loss of surfactant because of extraction into the oil phase by carboxylic material present in the crude oil may, however, be significant. The chemical mechanism for the wettability alteration by the cationic surfactant has been studied carefully, and it was suggested that cationic surfactants form 1:1 complexes with adsorbed organic carboxylates from the crude oil. The complexes are solubilized into micelles or the oil phase, and the water-wetness of the surface is improved.17 The wettability alteration process is catalyzed by sulfate, which will adsorb onto the carbonate rock, and decreases the positive surface charge. The electrostatic repulsion between the cationic surfactant and the rock surface is decreased, which will facilitate complex formation between the cationic surfactant and the adsorbed negatively charged carboxylic material.18 Two limestone cores with completely different permeabilities, 0.46 and 364 mD, were selected as test material. The permeability of the cores was above and below the permeability of the chalk cores, 13 mD, used in the cited previous experiments. To avoid differences in core properties, the same cores were used for both of the surfactant systems, C12TAB and Dodigen. The carboxylic material in the crude oil, as quantifies by the AN, is the most important wetting parameter in carbonates.16 The AN of the crude oil used in this study was 0.57 mg of KOH/g, and 2085
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Figure 5. Spontaneous imbibition at 50 °C of FW and SW þ 1 wt % C12TAB into core Res 52 using oil with AN = 0.57 mg of KOH/g (first restoration). Figure 7. Spontaneous imbibition at 50 °C into core Res 52. Comparison of C12TAB to Dodigen.
Figure 6. Spontaneous imbibition at 50 °C of FW and SW þ 0.5 wt % Dodigen into core Res 52 using oil with AN = 0.57 mg of KOH/g (second restoration).
the initial saturation of formation water was 10%. When cleaned cores were used without traces of sulfate, carbonate cores aged in crude oil of AN > 0.5 mg of KOH/g would act neutral to slightly oil-wet. Therefore, the cores were first imbibed with formation water without sulfate to confirm low water-wetness; thereafter, the imbibing fluid was exchanged to ordinary seawater containing cationic surfactant. No optimization of the salinity to obtain low IFT is needed for the surfactant to work properly. High-Permeable Limestone. The oil recovery from the highpermeable core using C12TAB and Dodigen is shown in Figures 57. In both cases, no oil was recovered using formation water as imbibing fluid, confirming very low water-wetness of the rock. The oil was displaced spontaneously from the core as the imbibing fluid was switched to seawater containing surfactant. An ultimate oil recovery of 49% of OOIP was recovered within about 6 days for the C12TAB system, while the Dodigen system needed about 20 days to reach the plateau recovery of 57% of OOIP. For comparison, the oil recovery profile was plotted in the same diagram, as shown in Figure 7. About 30% of OOIP was recovered within less than 8 h for both of the surfactants. With reference to the previous study on chalk, the high rate of oil recovery at the start must be linked to wettability alteration and activation of capillary forces. In the case of C12TAB, the oil recovery curve appeared to contain three distinct sections, which can be related to changes in the drive mechanism for the fluid flow, i.e., (1) mainly capillary forces, (2) both capillary and gravity forces, and (3) mainly gravity forces. Also, for the Dodigen system, IFT = 0.34 mN/m, it
Figure 8. Spontaneous imbibition at 50 °C of FW, SW þ 1 wt % C12TAB, and SW þ 0.5 wt % Dodigen into core Res 4-12 using oil with AN = 0.57 mg of KOH/g.
appeared to show a similar trend. The time frame for where both capillary and gravity forces were active appeared to be smaller, and gravity forces seemed to take over earlier because of the lower IFT. The ultimate oil recovery was higher, and about 18% of OOIP was produced by mainly gravity forces compared to about 9% for the C12TAB system. Thus, because of the impact of capillary forces by wettability alteration, about 70% of producible oil could be recovered within 12 days under lab conditions. Low-Permeable Core. The oil recovery from the low-permeable, 0.46 mD, limestone core is shown in Figure 8. Spontaneous imbibitions by formation brine (FW) only resulted in 4% recovery, which to some extent could be related to fluid expansion by increasing the temperature from room temperature to 50 °C. No significant increase in oil recovery was observed by switching the imbibing fluid from FW to SW containing C12TAB. The IFT was decreased from 0.67 to 0.34 mN/m by exchanging C12TAB by Dodigen, but no response in oil recovery was noticed. The imbibing fluid was again switched to C12TAB, and the temperature was increased to 70 and 90 °C without any oil production. Slightly above 20% of OOIP was recovered as the temperature was increased to 110 °C. The oil recovery was determined at room temperature, and it was not corrected for possible oil recovery because of thermal expansion. The vertical permeability of the carbonate matrix rock appeared to be crucial when using surfactant to combine capillary 2086
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Energy & Fuels forces by wettability alteration and gravity forces in a drainage process. In this case, it is impossible to discuss the impact of capillary and gravity forces on the fluid flow in terms of the inverse Bond number, NB1, because the wettability is changed during the imbibing process.19 Diffusion of Surfactant. The transport of surfactant into the matrix blocks appeared to be the critical rate-determining step for the field applications. The question is “how is the surfactant, micelles and monomers, transported to the imbibition front to create wettability modification?” Stoll and co-workers10 suggested that the wettability modification was limited to the rate of molecular diffusion of the surfactant. In low-permeable chalk (13 mD) at low initial water saturation, they estimated a diffusion coefficient in the order of Dm = 1011 m2/s. The mechanism for wettability alteration cannot be related to diffusion of the surfactant through the initial formation water because the process is also taking place in porous medium without initial water present.8 Masalmeh and Oedai11 also concluded from the experimental data that molecular diffusion alone cannot explain the rate and volume of oil recovered by cationic surfactantassisted oil recovery from fractured carbonate. If that should be the case, the diffusion coefficient should be at least a factor of 10 higher than the calculated value. The rate and efficiency of the wettability alteration process by cationic surfactants are related to the monomeric concentration of the surfactant and the presence of sulfate at the imbibing water front. The cationic surfactant does not adsorb onto the positively charged carbonate surface, but sulfate, which acts as a catalyst, has a strong affinity to the carbonate surface.20 Thus, at the imbibition front, the seawater may be depleted in sulfate and also in surfactant because of extraction of cationic surfactant into the oil phase by carboxylic material, which will affect the imbibition rate. Within 12 days, about 70% of producible oil was recovered from the Res 52 core using C12TAB and Dodigen, mostly by capillary forces because of wettability alteration. The molecular diffusion coefficient for C12TAB and Dodigen, as calculated by the method described by Stoll et al.,10 was determined to be 5.04 1010 and 8.23 1010 m2/s, respectively. When these conservative values were applied, the time required to achieve 40% oil recovery (70% of recoverable oil) from a 1 m3 reservoir block would be in the order of 2 and 4 years for C12TAB and Dodigen, respectively.
’ CONCLUSION Experimental studies have been performed to mimic oil recovery from naturally fractured limestone by using cationic surfactants dissolved in seawater to impose combined effects of capillary forces by wettability alteration and gravity drainage. The oil recovery was discussed in terms of rock permeability (0.46 and 364 mD) and IFT (0.34 and 0.67 mN/m). The limestone cores were made preferentially oil-wet using an oil with AN = 0.57 mg of KOH/g. The results were related to previous studies using low-permeable outcrop chalk (13 mD) as porous medium. The main results are summarized as follows: (i) Cationic surfactant of the type alkyltrimetylammonium, RN(CH3)3þ, will give an IFT value in the range of 0.11 mN/m between the injected surfactant solution (surfactant dissolved in seawater) and the actual crude oil. (ii) The oil recovery by spontaneous imbibitions into the high-permeable core (364 mD) indicated three different regimes for oil displacement: (1) oil recovery by capillary forces because of wettability alteration, (2) oil recovery
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by combined capillary and gravity forces, and (3) oil recovery by gravity forces. The impact of gravity forces increased as the IFT decreased. About 40% of OOIP could be recovered within 12 days by capillary and combined capillary and gravity forces (regimes 1 and 2). In the regime dominated by gravity forces (regime 3), about 9% additional oil was recovered at IFT = 0.67 mN/m, while 18% extra oil was produced using IFT = 0.34 mN/m. (iii) No oil was recovered from the low-permeable core (0.46 mD), indicating that permeability of the rock is crucial for oil recovery by surfactant in a spontaneous imbibition process. (iv) The fast recovery of oil from the high-permeable core indicated that a significant amount of producible oil can also be recovered in the field using surfactant, provided that the rock permeability is reasonably high, k > 300 mD. (v) The time scale for a diffusion process is linked to the square of the length scale of the medium. The time required to achieve 70% of the recoverable oil from the core plug in the laboratory was 1 day. When the upscaling equation was applied, the corresponding time required to achieve 70% of the recoverable oil from a 1 m3 reservoir block would be in the order of 2 years. (vi) A combined effect of SEGD and the wettability alteration in fractured, high-permeable, oilwet carbonate rock can provide an economically interesting opportunity.
’ AUTHOR INFORMATION Corresponding Author
*Telephone: þ47-466-276-58. E-mail:
[email protected].
’ ACKNOWLEDGMENT The Norwegian Research Council (NFR) and TOTAL are acknowledged for financial support. ’ NOMENCLATURE AN = acid number (mg of KOH/g) BN = base number (mg of KOH/g) D = core diameter (cm) DI = deionized Dm = diffusion coefficient (m2/s) FW = formation brine IFT = interfacial tension (mN/m) IS = ionic strength (mol/L) k = permeability (mD) L = core length (cm) NB1 = inverse Bond number OOIP = original oil in place (mL) PV = pore volume (mL) SW = synthetic seawater Swi = initial water saturation (%) T = temperature (°C) td = dimensionless time TDS = total dissolved solids (g/L) ’ REFERENCES (1) Zhang, P.; Austad, T. Colloids Surf., A 2006, 279, 179–187. (2) Zhang, P.; Tweheyo, M. T.; Austad, T. Energy Fuels 2006, 20, 2056–2062. (3) Strand, S.; Puntervold, T.; Austad, T. Energy Fuels 2008, 22, 3222–3225. (4) Zhang, P.; Tweheyo, M. T.; Austad, T. Colloids Surf., A 2007, 301, 199–208. 2087
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