Energy Fuels 2010, 24, 3551–3559 Published on Web 05/21/2010
: DOI:10.1021/ef1000908
Combined Low Salinity Brine Injection and Surfactant Flooding in Mixed-Wet Sandstone Cores Edin Alagic* and Arne Skauge UNI Research, UNI CIPR (Centre for Integrated Petroleum Research), All egaten 41, Bergen, Hordaland 5007, Norway Received January 25, 2010. Revised Manuscript Received April 18, 2010
The concept of surfactant flooding has long been recognized as a promising supplement to water-based enhanced oil recovery methods. In recent years, core displacement experiments performed on clastic rock samples using low salinity brine as injection fluid have proven to give a moderate increase in crude oil recovery. This paper presents a new hybrid EOR process where the effect of low salinity brine injection is combined with surfactant flooding. An anionic surfactant formulation was selected to give low interfacial tension (IFT) in a low salinity environment containing 0.50 wt % NaCl. The surfactant forms Winsor type I microemulsion at this salinity. Improved surfactant solubility and reduced adsorption or retention is among the advantages of using surfactant at low salinity conditions. This paper reports core flood experiments performed on outcrop sandstone cores using crude oil as the oil phase. Results show high oil recovery of more than 90% of original oil in place (OOIP) when surfactant is used in tertiary mode, i.e., after secondary waterflood. Destabilization of oil layers caused by change in brine salinity and simultaneous mobilization of the residual oil at low IFT is discussed as the possible underlying mechanism for the combined process of low salinity water injection with surfactant flooding. Low surfactant retention under these conditions may makes this hybrid EOR process more economically attractive compared to applying low salinity waterflood or surfactant flooding separately.
of the surfactant system with regard to optimizing physicochemical properties (e.g., interfacial tension toward oil phase, dynamic retention, and temperature stability). This can in some cases be difficult, time-consuming, and uneconomical. In contrast, low salinity environments open up a route to a wider portfolio of more commercially available and low-cost surfactant systems. At lower salinities, there is an increased possibility for surfactants that meet the current environmental and safety regulations. In the past decade, an extensive effort has been directed at low salinity waterflooding, Morrow et al.5 This paper represents a novel attempt to combine the benefits of low salinity waterflood with the advantages of the surfactant flooding. We have performed core flood experiments of combined low salinity water injection and surfactant flooding. Special attention is given to interpretation of effluent analysis (including pH and ion composition) as well as oil recovery and pressure difference profiles.
1. Introduction Capillary forces limit microscopic displacement efficiency and lead to trapping of oil during water injection in oil reservoirs. The capillary number, representing the balance between the capillary and the viscous forces, Stegemeier,1 has to be increased by several orders of magnitude before the residual oil after the waterflood can be mobilized. Surfactants may reduce the interfacial tension between the aqueous and the oil phase, which in turn will yield a higher capillary number creating favorable conditions for mobilizing trapped oil. For a typical anionic surfactant, parameters such as temperature, pH, and ionic strength of the water phase are important for the surfactant phase behavior and retention and must be taken into the consideration. Loss of surfactant in the porous media during surfactant flooding, due to adsorption, precipitation, and phase- and mechanical trapping, is a major problem. Corkill et al.2 and Connor et al.3 investigated the effect of temperature and pH, respectively, on the anionic surfactant adsorption and found out that an increase in both temperature and pH will normally reduce the surfactant adsorption. Similarly, Glover et al.4 reported that at low salinity the surfactant adsorption is reduced. Applying surfactant flooding at high salinity conditions requires a tailoring
2. Experimental Section 2.1. Core Material. Four core samples with designations B1, B2, B3, and B4 cut from the same block of Berea outcrop sandstone were used in this investigation. The physical properties of each core sample along with important experimental parameters are reported in Table 1. 2.2. Fluids. Synthetic sea water termed SW was used as the connate brine for all core samples. The amount of total dissolved solids (TDS) in SW was 36 321 ppm. The composition of the synthetic sea water is listed in Table 2. Low salinity brine, abbreviated LS, was prepared with doubly distilled water containing 0.50 wt % NaCl. The LS brine was used as the invading
*To whom correspondence should be addressed. Telephone: þ4755583644. Fax: þ4755588265. E-mail:
[email protected]. (1) Stegemeier, G. L. Presented at the SPE Symposium on Improved Oil Recovery, Tulsa, OK, Apr 22-24, 1974; Paper SPE 4754. (2) Corkill, J. M.; Goodman, J. F.; Tate, J. R. Trans. Faraday Soc. 1966, 62, 979–986. (3) Connor, P.; Ottewill, R. H. J. Colloid Interface Sci. 1971, 37, 642– 651. (4) Glover, C. J.; Puerto, M. C.; Maerker, J. M.; Sandvik, E. L. SPE J. 1979, 19, 183–193. r 2010 American Chemical Society
(5) Morrow, N. R.; Tang, G. Q.; Valat, M.; Xie, X. J. Pet. Sci. Eng. 1998, 20, 267–276.
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Energy Fuels 2010, 24, 3551–3559
: DOI:10.1021/ef1000908
Table 1. Experimental Parameters core ID
B1
B2
B3
B4
L (cm) D (cm) φ (%) Swi Soi kw (mD) ko(Swi) (mD)
7.92 3.70 22.6 0.24 0.76 630 731
8.21 3.73 23.7 0.22 0.78 642 710
8.10 3.73 23.1 0.24 0.76 715 625
8.04 3.72 23.2 0.21 0.79 561 592
SW/LS recovery (% OOIP) WBT (PV) Sor(SW)/(LS) volume injected (PV) kw(Sor(SW)/(LS)) (mD)
60.2 0.40 0.30 17.15 50
64.6 0.37 0.28 5.48 50
54.6 0.28 0.35 6.93 185
60.7 0.38 0.31 4.73 83
LS-S/high pH LS recovery (% OOIP) surf BT (PV) Sor(LS-S)/(high pH-LS) volume injected (PV) kw(Sor(LS-S)/(high pH-LS)) (mD)
92.3 0.71 0.06 14.74 203
94.4 0.75 0.04 6.89 320
74.5 1.28 0.19 7.53 276
67.9
Figure 1. Flow chart with experimental layout for core displacement experiments performed on cores B1, B2, B3, and B4.
0.25 8.45 128
Table 4. Properties of Injection Fluids
Table 2. Composition of High Salinity Brine (SW) ion
concentration (ppm)
Naþ Ca2þ Mg2þ ClHCO3SO42Kþ
11159 471 1329 20130 142 2740 349
F at 20 °C (g/cm3)
μ at 20 °C (cP)
AN (mg of KOH/g of oil)
BN (mg of KOH/g of oil)
A1
0.8784
13.80
2.84 ( 0.01
0.95 ( 0.10
μ (cP)
SW LS LS-S (pH 11.6) LS-S (pH 7.0) high pH-LS
1.15 1.01 1.74 1.01
IFT (vs crude oil A1) (mN/m) 23.5 16.5 1.24 10-2 1.71 10-2 1.8
second step, which is similar for cores B1, B2, and B3, the contribution to oil recovery by injection of the selected surfactant solution was evaluated. This made it possible to study the ability of the surfactant to remobilize and displace residual oil from the cores at different salinity. An attempt to distinguish and quantify the contribution of the alkaline part in the surfactant formulation to the total oil recovery was made by flooding core B4 with high pH, low salinity brine (abbreviated high pH-LS). Sodium hydroxide added to the low salinity brine raised the pH of the injection fluid so it could match and simulate the pH of the surfactant solution (pH 11.6). Pressure changes across the core samples were continuously monitored and logged during the injection with FUJI pressure transducers placed at the inlet and the outlet of the core. The production profiles of water and oil phase were determined volumetrically. Gravimetrical determination of respective phases was also used to confirm the results from the volumetrical method. Gravity stable floods, with nominal flow rate of 0.1 cm3/min, were performed on every core. Detailed description of various experimental methods including surfactant screening, ion analysis by inductively coupled plasma (ICP), and measurements of density, pH, interfacial tension (IFT), and viscosity are available in Supporting Information.
Table 3. Properties of Crude Oil (Filtered Oil) crude oil ID
fluid
brine in dynamic core displacement experiments and for surfactant screening. The selected surfactant used in this study was an internal olefin sulfonate Enordet 0242L (23.4% active matter) received from Shell Chemicals. The selected surfactant formulation was used without any pretreatment and as received from the supplier. The final composition of the chemical mixture used in core floods had the following composition: 0.50 wt % NaCl, 1.0 wt % Enordet 0242L, 1.0 wt % isoamyl alcohol (IAA). In this paper, it will be referred to as the low salinity surfactant solution, termed LS-S. Low salinity brine with high pH (pH 11.6) referred as high pH-LS is prepared with addition of sodium hydroxide (NaOH) to the LS brine. 2.3. Oils. The initial water saturation Swi of all cores was established by drainage with highly viscous oil Marcol 152. Filtered stock tank crude oil A1 was used for the aging of core samples and as the oil phase in core floods. Some of the important parameters of the crude oil A1 are listed in Table 3. 2.4. Core Handling. All core samples were saturated under vacuum with the synthetic sea water and allowed 3 days for ionic equilibrium to be established between the rock and the brine. Both the saturation and the drainage of the cores were carried out at ambient temperature. In order to establish a non-waterwet condition, all cores were enclosed in Hassler core holders with an overburden pressure of 30 bar, saturated with crude oil A1 at Swi, and aged at 90 °C for 10 weeks. After the aging cycle, all cores were flushed with additional 3 PV of fresh crude oil. 2.5. Dynamic Displacement Experiments. Figure 1 shows the flow chart of the experiments. The properties of injection fluids including viscosities and IFT values versus filtered crude oil A1 are reported in Table 4. Water floods were performed at Soi by injection of either low salinity brine (cores B1, B2, and B4) or sea water (B3) in the first step. This allowed us to directly investigate the effects of injection brine salinities on oil recovery. In the
3. Results In the following sections, we concentrate on reporting experimental results that include oil recovery and pH analysis of the effluent from various steps of the core displacement experiments. Pressure drop profiles and effluent ion analysis from different core samples show similar trends, and we therefore use core B1 in a further discussion. Water floods initiated at initial oil saturation, Soi, and at residual oil saturation, Sor, will be referred to as secondary and tertiary floods, respectively. 3.1. Low Salinity Waterflood Followed by Surfactant Flooding: Core B1. Continuous injection of 0.50 wt % NaCl (first step LS) resulted in a final oil recovery of 60.2% OOIP. As shown in Figure 2, the oil production at water breakthrough (WBT), which occurred at 0.40 PV, was 53.4% 3552
Energy Fuels 2010, 24, 3551–3559
: DOI:10.1021/ef1000908
Figure 2. Effluent pH, oil recovery (% OOIP), and water cut (%) as a function of volume injected (PV) for core B1.
Figure 3. Pressure drop profile (ΔP) and water breakthrough (PV) as a function of volume injected (PV) for core B1.
Figure 4. Concentration profiles for Mg2þ, Ca2þ, and Naþ (ppm) in the effluent as a function of volume produced (PV) from core B1.
OOIP. Hence, this represents a significant contribution to the total volume of the recovered oil in this step. Oil recovery after WBT resulted in a minor increase in recovered oil (6.8% OOIP). The production data gathered from the experiment revealed that during the first 2-3 PV injected, most of the major changes in both effluent concentration profile and oil
recovery took place. This flooding step was terminated at a high water cut and a stable ΔP value (Figure 3). There is a high degree of correlation between concentration profiles of Mg2þ, Ca2þ, and Naþ, as presented in Figure 4. Figure 4 also shows that the Naþ and Mg2þ concentrations in the effluent (3405 and 65 ppm, respectively) were significantly 3553
Energy Fuels 2010, 24, 3551–3559
: DOI:10.1021/ef1000908
Figure 5. Effluent pH, oil recovery (% OOIP), and water cut (%) as a function of volume injected (PV) for core B2.
divalent ions, Ca2þ and Mg2þ, were extremely low. However, the increase in Naþ concentration by approximately 1000 ppm was directly related to the contribution from the amount of surfactant in the injection fluid. As seen in Figure 4, the breakthrough of surfactant (1:1 ratio, compared to the surfactant concentration at the inlet) was registered at about 2.3 PV produced. 3.2. Low Salinity Waterflood Followed by Surfactant Flooding: Core B2. Core floods conducted on core B2 were attempted to reproduce the data obtained in the B1 floods. We find it important to check reproducibility of the core flood experiments but find this sadly ignored in the literature. All main features of the B2 core flood verified the results of the previous core flood. A continuous injection in the first step (LS) resulted in a final recovery of 64.6% OOIP. Compared to the flooding of B1, this was a slight increase in the recovery of more than 4%. The recovery at water breakthrough (0.37 PV-injected) was 54.7% OOIP, and this is approximately the same as in the case of core B1. Most of the recovered oil was produced during 1.67 PV injected (Figure 5). The ion analysis of the effluent showed similar features as in the case of core B1. A minor rise in the effluent pH was also observed (Figure 5). It was, however, less pronounced and lower than previously observed with core B1. No fines migration was observed this time in the accumulation tubes. The second step of flooding with surfactant (LS-S) was finished at recovery of 94.4% OOIP, which was again higher than in the case of B1. The surfactant breakthrough at 0.75 PV-produced, was first determined by two-phase titration and later on also confirmed by the Naþ concentration profile. The effluent pH profile showed a delayed response compared to oil recovery curve (see Figure 5). 3.3. Sea Water Flood Followed by Low Salinity Surfactant Flooding: Core B3. Continuous injection of sea water (first step SW) resulted in an oil recovery of 54.6% OOIP (Figure 6). Figure 7 shows the pressure drop across the core. Water breakthrough was detected at 0.28 PV, being considerably lower than for the LS floods performed on cores B1 and B2. The effluent pH slightly increased during the flood. Subsequently, LS-S flood was commenced in the high salinity environment and maintained for 7.5 PV. The surfactant solution, optimized for 0.50 wt % NaCl, was injected into the core saturated with high salinity brine. The first oil
lower than the concentration of corresponding ions in the connate sea water (11 159 ppm for Naþ and 1329 for Mg2þ). The Ca2þ concentration in the effluent (363 pm) showed a lower reduction when compared to the Ca2þ concentration in the connate water (417 ppm). The composition of the sea water is given in Table 2. This may indicate a different affinity for the rock surface regarding the ions investigated here. As depicted in Figure 4, the results clearly display a gradually decreasing concentration behavior up to approximately 1.9 PV. At this stage, we assumed that almost all the remaining cations originally present in the connate water were exchanged. The concentration of Naþ stabilized around 2000 ppm, which was in good agreement with the concentration of Naþ in the injection fluid. A constant production of Ca2þ through the entire first flooding step may indicate a continuous cation exchange at the clay surface. The concentration of Mg2þ was at all times noticeably lower compared to the other ions in the effluent. Small traces of fines accumulation in the sampling tubes were detected. The experiment was extended with a continuous injection of the surfactant solution (second step, LS-S) resulting in a residual oil saturation of 6% (i.e., corresponding to 92.3% OOIP). The production data clearly show that the increase in effluent pH is slightly delayed compared to the increase in the oil recovery (Figure 2). The reproducibility of the pH measurements was found to be (3%, which cannot explain the oscillation in measured pH in the interval 22-28 PV. The observed increase in pressure drop across the core from 25 to 75 mbar is attributed to a two-phase flow and not to the viscosity of the microemulsion. The viscosity of the microemulsion (1.85 cP) at this salinity is slightly higher than the viscosity of the injection fluid (1.75 cP). The breakthrough of the surfactant was determined by the two-phase titration method. The results from this method correspond with the Naþ concentration profile determined by ICP (note that the surfactant system used contains sodium as a counterion). Therefore, the observed change in Naþ concentration from ICP data may give indirect information on the surfactant propagation in the core. First traces of the surfactant in the aqueous effluent phase were recorded at 0.71 PV-produced. On the basis of the results presented in Figure 4 (second step LS-S), the concentration levels of both 3554
Energy Fuels 2010, 24, 3551–3559
: DOI:10.1021/ef1000908
Figure 8. Effluent pH, oil production (% OOIP), and water cut (%) as a function of volume injected (PV) injected for core B4.
Figure 6. Effluent pH, oil production (% OOIP), and water cut (%) as a function of volume injected (PV) for core B3.
is considerably lower compared with the oil recovery obtained from core floods in tertiary mode, where LS-S solution was used. A relatively slow increase of the effluent pH is the prominent feature, as shown in Figure 8, and reflects the lack of ability of the caustic solution to establish a stable and high pH plateau early in the flood. Despite the continuous injection for several pore volumes, the effluent never did attain the pH value of the injected solution. The delay in OH- breakthrough is a result of loss of alkalinity resulting from ion exchange and mineral dissolution, as previously stated by Novosad.7 Deterioration of the alkaline solution in the pore space of the core may be explained by the presence of Ca2þ. Even though the initial concentration levels of Ca2þ was fairly low (25 ppm), it negatively affected the success of the flood. When Ca2þ concentration dropped below 10 ppm, after approximately 4 PV was injected, the pH of the effluent started slowly to rise. A small increment in the effluent pH was detected at Ca2þ concentration levels lower than 5 ppm.
Figure 7. Pressure drop profile (ΔP) and water breakthrough (PV) as a function of volume injected (PV) for core B3.
4. Discussion
production was recorded at 1.7 PV injected, which differed significantly from the results obtained previously with cores B1 and B2. After the surfactant breakthrough at 1.28 PV was produced, the aqueous phase in production tubes had a milky and nontransparent color with unclear boundaries toward the oleic phase. Because of high turbidity, the volumes of different phases were therefore determined by centrifugation at constant rotation at 3400 rpm for 15 min. However, as previously mentioned, increased turbidity was observed visually, but significant precipitation was not observed. The increase in effluent pH and oil production correlated well with the surfactant breakthrough (Figure 6). 3.4. Low Salinity Waterflood Followed by High pH Low Salinity Flooding: Core B4. Upon injection of LS solution, water breakthrough occurred at 0.38 PV injected. However, additional oil was observed after WBT, resulting in total 60.7% OOIP. A minor increase in the effluent pH was also registered. All monitored ions displayed comparable trends to those of cores B1 and B2. In the second flooding step, low salinity brine with adjusted pH (pH 11.6) was injected continuously. Note that this pH value is the same as that of the original LS-S solution. Any additionally produced oil from this step could therefore be credited to the caustic properties of solution only. Change from LS to high pH-LS solution increased oil recovery by 7% OOIP (see Figure 8). Evidently, this result
4.1. Comparing Secondary Water Floods at Different Salinities. Composition of brine and its interactions with rock matrix may influence differential pressure during waterflood. After a short period of injection during LS floods, ΔP increased rapidly to a maximum value followed by a relatively sharp decrease (see Figure 3). The small pressure increase recorded at the end of the first flood with core B1 may be due to the fines migration in the core. In the case of the secondary SW flood ΔP increased slowly in the interval before the breakthrough, then continued in a slow and decreasing trend (see Figure 7). The pressure response showed that the increase in recovery in LS floods was accompanied by an increase in resistance to flow of brine in the secondary mode. With regard to WBT in the first flooding steps, LS floods led to a later breakthrough compared to SW floods. This has previously been reported by Morrow et al.5 in their work with the extent of imbibition and breakthrough in water floods using diluted brine. It is important to point out that a considerable portion of produced oil in LS floods originates from the interval before WBT. Even though core B1 was flooded with 17 PV compared to 5.5 PV and 4.7 PV (6) Novosad, Z.; Novosad, J. SPE J. 1984, 24, 49–52. (7) Zhou, X.; Morrow, N. R.; Ma, S. SPE J. 2000, 5, 199–207.
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: DOI:10.1021/ef1000908 (Winsor’s type I).9 A significant increase in the salinity results in a formation of water-in-oil microemulsions (Winsor’s type II) where the surfactant moves over to the oil phase. An increasing salinity gradient is partially responsible for trapping the surfactant in the oil phase and delaying the breakthrough. Divalent cations also form insoluble sulfonate salts, which tend to precipitate from the aqueous solutions.10 4.3. Effluent Ion Analysis. On the basis of the published literature, a common understanding is that injection water displaces connate water not in a piston-like manner but with some degree of mixing. This degree of mixing is embedded in simulation models to successfully match coreflood results and to simulate field-scale projects.13 Evidence that largely supports these findings, namely, connate water banking, has earlier been reported for sandstones by Russell et al.14 In the case of LS floods, the effluent ion analysis showed conclusively that the connate water bank, ahead of the injection water, was displaced first (see Figure 4). Nonetheless, the detected ion concentrations at the outlet were initially lower than the concentration of the respective ions present in the connate water. Recovery of monitored ions is shown below as Ci/C0, i.e., the ratio of initial ion concentration (Ci) in the effluent ions at the water breakthrough (see Figure 4) to the concentration of corresponding ions in the connate water (C0) (core B1 is used in this example):
Figure 9. Oil production (% OOIP) for secondary LS floods (cores B1, B2, and B4) and SW flood (core B3) as a function of volume produced (PV).
(cores B2 and B4, respectively) there is not a direct correlation between the duration of floods and the total oil production (see Table 1). Figure 9 clearly shows the distinguishing features between LS and SW floods. Extended aging time results in a decrease of water wetness as found by Zhou et al.7 A qualitative assessment of the wettability has been made on the basis of the shape of the oil production curves and the end point relative permeability to water after the secondary waterfloods. The impact of wettability on the performance of low salinity waterfloods and combined low salinity surfactant flood will be discussed in an upcoming publication. The oil production plateau occurred earlier for LS floods, which may be associated with the cores being water-wet. On the other hand, the SW flood exhibited different behavior, showing gradual and slow oil production over almost 5 PV injected. The observed phenomenon indicates a different wettability state caused by the difference in brine composition. Furthermore, even though all LS floods led to a lower residual oil saturation compared to the SW flood, the measured values of end point water permeabilities after LS floods were significantly lower compared to that after the SW flood (see Table 1). Consequently, it seems that LS floods behave more as a water-wet system (i.e., lower kw(Sor)) while SW floods show resemblance to a less water-wet behavior (i.e., higher kw(Sor)). 4.2. Comparing Tertiary Surfactant Floods. Figure 10 depicts oil production curves from tertiary surfactant floods initiated in either low or high salinity brine. It is clear that significantly higher oil recovery is achieved when surfactant solution is introduced into a pre-established low salinity (30-33% OOIP) than high salinity environment (20% OOIP). The delayed surfactant breakthrough observed for core B3 may be explained by an unfavorable salinity gradient encountered here. The presence of the divalent ions such as Mg2þ and Ca2þ originated from the high salinity injection water in the previous flooding step, which made the actual surfactant less effective in reducing the interfacial tension.8 At low salinity, the surfactant stays in the aqueous phase where it forms microemulsion by solubilizing the oil in water
Ci ðMg2þ Þ ¼ 0:05; C0
Ci ðNaþ Þ ¼ 0:31; C0
Ci ðCa2þ Þ ¼ 0:74 C0
These results illustrate that Mg2þ displays the most pronounced concentration drop. Naþ also shows notable reduction, while on the other hand Ca2þ shows a minor decrease. A possible explanation for this is that the sampling volumes are too large to detect changes in the salinity. The volumes of the effluent fractions are optimized primarily to minimize experimental error regarding quantification of oil production. Effluent ion concentration is analyzed in Figures 11 and 12. The ratio between the cumulative mass of produced ions (mcum) and the total mass of the respective ions (m0), which is a quantity originating from Swi (displayed as y-axis), is plotted against the volume of water phase produced (x-axis) in Figure 11. It shows that the mass ratio for Mg2þ is less that 1 for the duration of flooding cycle. This means that most of the Mg2þ is retained in the core samples. The Ca2þ effluent profile displays a constant production of Ca2þ. If, for the sake of simplicity, we assume connate water banking with zero mixing, then Figure 11 shows that the mass ratio for Ca2þ reaches 1.0 at 0.30 PV produced water. At this volume all the Ca2þ ions from connate water are exchanged. It is therefore likely that dissolution of calcium containing minerals is the major source of Ca2þ in the production interval after 0.30 PV. Ion binding or specific interactions between charged sites in the rock matrix and higher valency ions promote wettability alteration toward less water-wet state, according to (10) Trushenski, S. P.; Dauben, D. L.; Parrish, D. R. Soc. Pet. Eng. J. 1974, 14, 633–642. (11) Jerauld, G. R.; Lin, C. Y.; Webb, K. J.; Seccombe, J. C. SPE Res. Eval. Eng. 2008, 11, 1000–1012. (12) Russell, R. G.; Morgan, F.; Muskat, M. Trans. AIME 1946, 170, 51–61. (13) Buckley, J. S.; Liu, Y.; Monsterleet, S. SPE J. 1998, 3, 54–61. (14) Skauge, A.; Standal, S.; Boe, S.; Skauge, T.; Blokhus, A. M. Presented at the SPE Annual Technical Conference and Exhibition, Houston, TX, Oct 3-6, 1999; Paper SPE 56673.
(8) Paul, G. W.; Froning, H. R. J. Pet. Technol. 1973, 25, 957–958. (9) Winsor, P. A. Solvent Properties of Amphiphilic Compounds; Butterworth's Scientific Publications: London, 1954.
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Figure 10. Incremental oil recovery of residual oil after the first flood (%) for tertiary LS-S floods (core samples B1-B3) and high pH-LS flood (core B4) as a function of volume produced (PV).
The ion production profiles from LS-S floods (cores B1, B2, and B3) and high pH-LS flood (B4) are summarized in Figure 12. However, the production of Ca2þ from resident minerals is much higher for core B2. This may be closely connected with the extent of flooding at previous step, LS, which most likely has contributed to a more effective washing out of Ca2þ from core B1. Core B1 was flooded with 17.15 PV compared to 5.48 PV in the case of core B2. On the basis of the magnitude of the produced Ca2þ, it seems that injecting the surfactant solution at high pH has minimized further production of Ca2þ in both cases. Core B4 flooded with high pH-LS showed even lower concentrations of both ions. The core B3 that in the first step was flooded with sea water displayed a different trend in ion production in the LS-S step. Figure 12 shows a small production of Mg2þ from the core matrix, in an amount that differs for cores B1, B2, and B4. It appears that the encountered salinity gradient during LS-S flood may have destabilized minerals also containing Mg2þ. 4.4. Alkaline Effect. As previously mentioned, a crude oil with high acid number has been used in this investigation. According to Skauge et al.,16 the amount of polar components (NSO and asphaltenes) in the crude oil is proportional to the amount of acids and bases. Asphaltenes, heavy polar organic species, take part in wettability alteration creating less water-wet condition through the adsorption onto clay material.17 A low salinity brine can destabilize the bonding between the clay surface and polar oil components.18 Lager et al.18 have proposed this as the working mechanism for low salinity brine injection. Injection of low salinity brine can therefore induce a transition from a less water-wet to a more water-wet state, which again may result in higher oil recovery. This may explain why the low salinity brine injection does not give satisfying results in already strongly water-wet systems and in fired (no clay) cores.16
Figure 11. Ratio between the cumulative produced mass of ions (mcum) and total mass at Swi (m0) as a function of volume water produced (PV) for core B1.
Buckley et al.15 For example, Ca2þ and Mg2þ at ambient temperature are highly hydrated ions. At elevated temperatures, as for instance during the aging, the activity of these ions increases and enhances the binding affinity for the solid surface and for polar components in the oil phase. Interactions between crude oil and charged surface sites as a part of mechanism that involve divalent ions as intermediate or bridging species would lead to a decreased water wetness of the system. This will lead to a decrease of water film thickness and/or water film connectivity, resulting in partial breakage of the brine film in the pore space. The Ca2þ effluent profile suggests an effective displacement of the connate water by the injection brine, and it can therefore be assumed that Mg2þ is strongly adsorbed by the minerals in the core samples and that the injection of the NaCl solution could not destabilize the bonds between Mg2þ and its surroundings. The behavior of Ca2þ appears to be of a different nature that needs further investigation.
(16) Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. Presented at the International Symposium of the Society of Core Analyst, Trondheim, Norway, Sep 12-16, 2006; Paper SCA2006-36. (17) Fan, T.; Buckley, J. S. Presented at the International Symposium of the Society of Core Analysts, Toronto, Canada, Aug 21-25, 2005; Paper SCA 2005-01. (18) Cooke, C. E.; Williams, R. E.; Kolodzie, P. A. J. Pet. Technol. 1974, 26, 1365–1374.
(15) Sposito, G. The Chemistry of Soils; Oxford University Press: Oxford, U.K., 1989.
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Figure 12. Ratio between the cumulative produced mass of ions (mcum) and the total mass of respective ions from Swi (m0) as the function of volume water phase produced (PV) for the cores B1, B2, and B3 (the second step, LS-S) and B4 (high pH-LS). Blue (Ca2þ) and green (Mg2þ) solid lines represent the points where all ions from the core at Sw = 0.65 were fully displaced (assuming no mixing of injected and connate water). Table 5. Capillary Numbers (Nc) core ID
Nc(LS/SW)
Nc(LS-S/high pH-LS)
B1, B2 B3 B4
9.5 10-8 7.5 10-8 9.5 10-8
2.2 10-4 2.2 10-4 8.7 10-7
change in the phase behavior compared with when the original surfactant system (pH 11.6) was used. The measured IFT (1.71 10-2 mN/m) showed a minor change compared to the IFT measured for the original LS-S solution (1.25 10-2 mN/m) with pH 11.6. Apparently, even a high acid number crude (see Table 3) gives a minimal change in IFT at high pH when the surfactant is present. Table 5 summarizes capillary numbers for various flooding steps in this study. The increase in capillary number from 9.5 10-8 to 2.2 10-4 caused by lowering IFT with LS-S solution has resulted in a residual oil saturation of 6% and 4% for cores B1 and B2, respectively. According to the findings of Garnes et al.,19 the residual oil saturation should in our case be approximately 40%. Non-water-wet conditions would most likely require an even higher Nc to mobilize the residual oil to the same extent. The oil recovery increase for the cores floods investigated here cannot only be credited to the surfactant. Joint contribution from the alkaline effect and the phenomenon associated with change to low salinity brine may also play an important role in this study
Fan and Buckley17 concluded that IFT decreased with increasing acid number at alkaline conditions above pH 10, which is the case here. Further, in an effort to determine the magnitude of the alkaline effect, the following control experiments were performed: (1) The pH of the LS solution was adjusted by addition of sodium hydroxide (NaOH) to match the pH of the LS-S solution. The IFT was reduced from 16.5 mN/m (pH 7.0) to 1.8 mN/m (pH 11.6). The phase behavior tests with crude oil and high pH- LS solution did not show any change in the phase volumes, but the water phase showed increased turbidity, indicating the presence of solubilized oil. The IFT measurements were conducted between the equilibrated water and oil phases. These measurements confirmed that a reduction in IFT is consistent with a high amount of the acid in the crude and generation of soap.18 As shown in Table 5, the calculated capillary number for this flood (Nc = 8.7 10-7) is still below the critical capillary number, Ncc, found for water-wet Berea sandstones (Ncc = 4 10-6) by Garnes et al. Figure 10 shows the response in oil production upon injection of high pH-LS solution compared to tertiary LS-S injection. The response in oil recovery is much faster in the latter case; however, the injection of high pH-LS solution showed the largest increase in oil recovery (18%). These results suggest that the original surfactant system provides the major contribution to the oil recovery in both the low (80-84%) and the high salinity (43%) environment. (2) The pH of the LS-S solution is reduced to neutral (pH 7.0) by addition of hydrochloric acid (HCl). With this, the excess of alkali agent in the surfactant system is neutralized and the performance of only the surfactant system could be evaluated. Static phase behavior tests with neutralized surfactant system did not show any visually detectable
5. Conclusion The additional oil recovery by change from sea water to low salinity was about 6 saturation units. Water breakthrough was also delayed in the case of low salinity floods compared to the sea water injection. The reduced two-phase production period after water breakthrough in the low salinity core floods indicates a more water wet behavior compared to the sea water injection. High tertiary oil recovery was obtained by surfactant injection after stabilizing a low salinity environment. The results were confirmed in three experiments. The tertiary oil recovery was significantly reduced when surfactant was injected without a prior preflush with low salinity brine. (19) Garnes, J. M.; Mathisen, A. M.; Scheie, A.; Skauge, A. Presented at the 7th SPE/DOE Symposium on Enhanced Oil Recovery, Tulsa, OK, Apr 22-25, 1990; Paper SPE 20264.
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Energy Fuels 2010, 24, 3551–3559
: DOI:10.1021/ef1000908
The alkaline environment of the surfactant system could not explain the additional oil recovery. The low salinity surfactant floods gave higher oil recovery than what could be predicted by the capillary number relationship. The effluent ion analyses from LS-floods clearly show that Mg2þ is strongly retained in the core matrix. Continuous production of Ca2þ indicates mineral dissolution. The promising results inspire further investigation and optimization of combined low salinity and surfactant flooding processes.
kw(Sor(high pH-LS)) = endpoint permeability to water after high pH-LS flood kw(Sor(LS)) = endpoint permeability to water after low salinity brine flood kw(Sor(LS-S)) = endpoint permeability to water after low salinity surfactant flood kw(Sor(SW)) = endpoint permeability to water after sea water flood L = core length LS = low salinity brine (0.50 wt % NaCl solution) LS-S = low salinity surfactant solution (0.50 wt % NaCl solution, 1.0 wt % Enordet 0242L, and 1.0 wt % isoamyl alcohol) m0 = initial mass of ions in the core Marcol 152 = mineral oil mcum = cumulative mass of ions in the effluent NaOH = sodium hydroxide Nc(high pH-LS) = capillary number for low salinity brine flood with high pH Nc(LS) = capillary number for low salinity brine flood Nc(LS-S) = capillary number for combined low salinity surfactant flood Nc(SW) = capillary number for sea water flood Ncc = critical capillary number PV = pore volume Soi = initial oil saturation Sor(high pH-LS) = residual oil saturation after low salinity with high pH flood Sor(LS) = residual oil saturation after low salinity flood Sor(LS-S) = residual oil saturation after combined low salinity surfactant flood Sor(SW) = residual oil saturation after sea water flood SBT = surfactant breakthrough SW = synthetic sea water Swi = initial water saturation TDS = total dissolved solid WBT = water breakthrough φ = core porosity μ = viscosity F = density
Acknowledgment. We acknowledge the Petromaks program at the Norwegian Research Council for financial support. The University College in Bergen (Institute of Chemistry), Norway, is also acknowledged for placing the ICP instrument at our disposal. The authors thank Dr. Tormod Skauge for valuable suggestions for improvement throughout this paper. Supporting Information Available: Screening of surfactant systems and details of measurement procedures. This material is available free of charge via the Internet at http://pubs.acs.org.
Nomenclature Abs = absolute AN = acid number BN = base number BT = breakthrough C0 = concentration of ion in the formation water Ci = initial ion concentration in the effluent conc = voncentration D = core diameter Enordet 0242L = onternal olefin sulfonate surfactant high pH-LS = low salinity solution with high pH HCl = hydrochloric acid IAA = isoamyl alcohol ID = identification IFT = interfacial tension ko(Swi) = permeability to oil at initial water saturation ko = permeability to oil kw = permeability to water
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