Enhanced Oil Recovery (EOR) by Combined Low Salinity Water

Article pubs.acs.org/EF

Enhanced Oil Recovery (EOR) by Combined Low Salinity Water/ Polymer Flooding Behruz Shaker Shiran* and Arne Skauge Centre for Integrated Petroleum Research (Uni CIPR), University of Bergen, Allégaten 41, 5007 Bergen, Norway ABSTRACT: Recently, low salinity brine injection has been given a great interest as a technique for enhanced oil recovery (EOR) by waterflooding. Varying experimental results have been reported in the literature, from many promising results to limited or no effects of low salinity. The application of low salinity water in combination with other established EOR processes (e.g., surfactant flooding and polymer flooding) is of great interest. The combined processes involve dampening capillarity to avoid trapping of mobilized oil, reducing residual oil saturation (Sor), and altering frontal stability and sweep. In this article, we address the questions of timing of LS injection and the added benefit of polymer injection. Secondary-mode (at initial water saturation) and tertiary-mode (after seawater residual oil saturation) low salinity waterflooding experiments were performed on outcrop Berea sandstone core material. The main results are the oil recovery efficiencies of these two different flooding modes. These results show an increase in oil recovery of about 13% of the original oil in place (OOIP) in secondary-mode compared to tertiary-mode low salinity waterflooding. Moreover, the effect of polymer injection was found to be more positive when low salinity was initialized from the start of water injection (secondary mode). In this case, the final recovery factor increased to about 90% OOIP. Possible mechanisms for low salinity and low salinity polymer injection are discussed.

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INTRODUCTION Increased oil recovery by substantially lowering the injection brine salinity or modifying the brine composition of the injection water has been reported in numerous experimental studies and field trials for both tertiary (residual oil condition) and secondary (initial water condition) modes of water flooding.1−11 The mechanism or mechanisms behind the low salinity effect (LSE) are not yet well understood and have been the subject of extensive investigation and systematic research during the past 10−15 years. On the basis of many experiments, Tang and Morrow3 concluded that mixed-wet porous media containing clay and the presence of connate water are necessary conditions for the LSE. They related the increased oil recovery to wettability alteration toward more water-wet condition by fines migration during low salinity water injection. In later studies, several other mechanisms have been proposed by different researchers as reasons for the LSE. The mechanisms often referred to as key factors in sandstone include the following: (1) release and migration of mixedwet clay fines, which results in the alteration of wettability toward a more water-wet state and, therefore, oil mobilization and production3 and effective microscopic diversion;12,13 (2) mineral dissolution and ion-exchange reactions, which increase the pH through the formation of excess hydroxyl ions, OH¯, thereby causing a reduction in interfacial tension (IFT);14 and (3) multicomponent ionic exchange (MIE)15 between adsorbed crude oil components, connate brine, and clay particles, which leads to the development of a “self-freshening” zone within the water-flooded region,16 double layer expansion17 that results in the desorption of organic polar compounds from the rock surface, oil layer destabilization, and microscopic diversion.12,13 Boussour et al.18 presented the different mechanisms proposed in the literature as being responsible for the LSE and provided experimental counterexamples, showing that the LSE is very sensitive to a combination of different parameters inherent in the crude oil−brine−rock system. © 2013 American Chemical Society

An increase in pH, for instance, has been reported in many articles as the reason for the LSE. However, numerous experimental studies have shown no correlation between the LSE and changes in pH. That is, there are reports of a benefit to low salinity with a slight change or even a decrease in pH,14,19,20 as well as evidence of significant increases in pH with no corresponding increase in oil recovery.21 A local pH increase at the water−clay interface was proposed as a factor by Austad et al.,22 who stated that, in a pH-buffered system (e.g., reservoir conditions under which CO2 acts as pH buffer), even though the effluent pH might not show any increase, the LSE will be observed because acid−base reactions are very fast. This is because a local pH increase close to the clay surface will desorb the organic material from the clay surface and, because of the dynamic nature of the flow conditions, the desorbed material will be transported away from the adsorption sites and the clay surface will become more water-wet. Austad et al.22 also attributed the multicomponent ionic exchange (MIE) mechanism proposed by Lager et al.15 to the precipitation of Mg(OH)2 as a result of a local pH increase during low salinity water injection. Recently, Aksulu et al.23 performed a study with the objective of confirming that pH is a key parameter in the LSE and concluded that effluent pH monitoring during successive flooding of a sandstone reservoir core with appropriate high-salinity/low salinity/ high-salinity brines under reservoir temperature conditions might be a valuable first approach to evaluate the possibility of achieving increased oil recovery by using low salinity water. In parallel with the ongoing discussions on the contribution of pH to the LSE, other proposed mechanisms (e.g., wettability alteration, fines migration) are also debated in the literature, and Received: September 18, 2012 Revised: February 11, 2013 Published: February 12, 2013 1223

dx.doi.org/10.1021/ef301538e | Energy Fuels 2013, 27, 1223−1235

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so far, no single proposed mechanism is conclusive from the point of view of experimental observations. Therefore, more studies and investigations are needed to further understand the mechanisms involved in increased oil recovery upon low salinity water injection. The goal of this article is to contribute to the understanding of mechanisms involved in the low salinity effect and to investigate the synergy of low salinity waterflooding and polymer injection. In our previous work,24 we studied the effects of different initial wettability states on oil recovery by tertiary-mode low salinity waterflooding on Berea and Bentheimer outcrop sandstones. The results showed no increased oil recovery by the LSE in strongly water-wet Bentheimer cores and limited oil recovery (∼2% OOIP) in oil-wet samples. The oil recovery from intermediate-wet Berea cores was marginal. In the current study, the aim was to investigate the efficiency of secondaryversus tertiary-mode LS injection on strongly water-wet and intermediate-wet Berea sandstone cores. After the LS injection experiments, the cores were subjected to polymer flooding to examine further enhanced oil recovery by combined low salinity water/polymer injection.

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Table 2. Properties of Fluids Used in Experimental Work

11156 471 1330 20129 139 2743 350 36318

AN (mg of KOH/g)

BN (mg of KOH/g)

pH

diluted crude oil SSW LS polymer (300 ppm) polymer (1000 ppm) LPS (300 ppm)

2.40 1.07 1.03 2.60 7.50 2.20

0.88 1.03 1.00 − − −

1.71 − − − − −

0.57 − − − − −

− 8.45 7.50 − − −

content content content component (wt % bulk) component (wt % bulk) component (wt % bulk) illite/mica kaolinite chlorite

3.0 3.2 1.7

quartz feldspar plagioclase

87.5 1.9 0.9

calcite dolomite siderite

trace 0.9 0.9

placed in oven at 70 °C for about 48 h. The dried cores were then mounted individually in an Exxon-type core holder, and the overburden pressure was set at 20 bar. A vacuum pump was used to evacuate air from the core samples. Then, the cores were saturated with synthetic seawater, and their porosity and permeability were measured. After permeability measurements, the synthetic seawater was displaced by high-viscosity Marcol 152 to attain initial water saturation (Swi) conditions in the core plugs. Then, several pore volumes of n-decane mineral oil were injected at different flow rates to displace the Marcol 152 and measure the oil permeability at Swi. The physical properties of the core plugs used in this study are reported in Table 4. Aging with Crude Oil. Core plugs mounted in a core holder were placed in heat cabinet at 110 °C and were aged by injection of crude oil for 4 weeks to obtain wettability states other than strongly water-wet. As reported in a previous work,24 the unaged Berea cores were strongly waterwet, and wettability studies for cores S1−S4 showed wettability changes toward the intermediate-wet state after aging with crude oil (Figure 1). Core Flooding Experiments. A pair of core plugs was mounted together in a longer core holder, and a confining pressure of 20 bar was applied. Five displacement experiments were performed in this study. Intermediate-wet cores S6−S7 and S3−S4 were selected to examine LS injection at intermediate wettability in secondary and tertiary modes, respectively. Also, strongly water-wet core S11 and composite core S9−S10 were used to perform low salinity tests under water-wet conditions in secondary and tertiary modes, respectively. The intermediate-wet core S12 was used to examine the reproducibility of increased oil recovery by combined low salinity water/polymer flooding. The experiments were performed at room temperature (22 °C). All flow experiments started at a flow rate of 0.1 cm3/min, and then the flow rate increased to 0.2, 0.5, and 1.0 cm3/min to eliminate capillary end effects. For each flow rate, water was injected until no more oil was produced and the pressure difference across the cores was stabilized. The differential pressure across the core plugs was continuously recorded by a data gathering system during the flooding experiments. Estimation of Capillary Pressure (Pc) and Relative Permeability Curves. To obtain the capillary pressure and relative permeability curves, the experimental data (differential pressure, production data, and end-point data) were imported into the core flood simulator Sendra.25 This simulator is a one-dimensional fully explicit black oil simulator and was used to history match the core flood experiments and estimation of Pc and Kr curves. To obtain the best estimation of these curves from experimental data, the Corey26 correlation was used for relative permeability, and the Skjaeveland et al.27 correlation was used for the capillary pressure.

Table 1. Composition of Synthetic Seawater (SSW) concentration (ppm, mg/kg)

density (g/mL)

Table 3. Mineralogical Composition of Berea Samples

EXPERIMENTAL SECTION

ion

viscosity (cP)

Porous Media. Core plugs from outcrop Berea sandstone were used in this study. Mineralogy measurements by X-ray diffraction (XRD) showed that the Berea samples contained 7.9% clay minerals, including 3.2% kaolinite (Table 3). The core plugs were cut from whole cores and

Brines. Synthetic seawater (SSW) was used primarily for saturating and establishing connate water in core plugs and also as the injection fluid in tertiary-mode low salinity experiments. The SSW was prepared by dissolving different salts in distilled water such that the total dissolved solids (TDS) was about 36000 ppm (mg/kg). Table 1 lists the

Na+ Ca2+ Mg2+ Cl− HCO3− SO42− K+ TDS

fluid

composition of the synthetic seawater used in this study. This SSW also was diluted by a factor of 10 to prepare low salinity water (LS) with a salinity of about 3600 ppm (mg/kg), which was used as the injection fluid during low salinity waterflooding experiments. The ionic strengths of the SSW and LS were 0.69 and 0.069, respectively. Polymer Solution. Polymer solutions were prepared by addition of the required amount of Flopaam 3630S (SNF Floerger) polyacrylamide with a hydrolysis degree of 25−30% and a molecular weight of 20 million Da to low salinity water. Polymer solutions were prepared in concentrations of 300 and 1000 ppm. Linked Polymer Solution. Linked polymer solution (LPS) was prepared by adding aluminum citrate (AlCit) cross-linker to polymer solution at a polymer-to-aluminum ratio of 30:1. Oils. The initial water saturation (Swi) of the core plugs was attained by injection of a high-viscosity mineral oil called Marcol 152. After Swi had been established in all core plugs, Marcol 152 was replaced by another mineral oil, n-decane. This mineral oil was also used to measure the oil permeability of the core plugs at initial water saturation. A North Sea stock tank oil (filtered) was used as a crude oil for aging of the core plugs and as the oil phase in flow experiments. The viscosity of this crude oil was in the range of 50−80 cP (from different production wells). Compared to seawater and low salinity water, which have a viscosity of only 1 cP, the mobility ratio was highly unfavorable. To achieve a more effective displacement in flow experiments, the crude oil was diluted by addition of xylene to reach a favorable viscosity. Table 2 lists some properties of the injection fluids used in this experimental work at 22 °C. 1224


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Table 4. Physical Properties of Core Samples

a

core ID

L (cm)

D (cm)

PV (mL)

porosity (%)

Swi (%PV)

Kw (mD)

Ko at Swi (mD)

Ko at Swia (mD)

S0 S1 S2 S3 S4 S6 S7 S9b S10b S11b S12

5.82 6.0 6.23 6.17 6.17 6.26 6.17 5.92 5.98 8.82 6.90

3.78 3.7 3.76 3.73 3.73 3.72 3.73 3.71 3.74 3.76 3.76

12.69 12.35 13.28 13.18 12.63 12.54 12.85 12.35 12.65 17.77 15.18

19.55 19.14 19.19 19.55 18.73 18.43 19.04 19.31 19.25 18.11 19.81

19 25 23 20 21 22 22 22 22 22 25

98.98 103.86 90.23 109.17 90.96 84.61 117.43 95.06 101.70 75.14 108.90

− 128.92 110.86 133.02 118.43 109.43 146.02 118.40 122.12 89.20 −

− 78.69 78.68 83.68 70.72 93.93 − − − −

Oil permeability after aging. bUnaged cores.

Figure 1. Amott/Harvey-USBM wettability plot, showing intermediate-wet state for aged cores S1−S4 (red) and strongly water-wet state for unaged core S0 (blue).24.

Figure 2. Oil recovery factor, differential pressure, and injection rate as functions of volume injected for strongly water-wet composite core S9−S10 (tertiary-mode LS injection).

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EXPERIMENTAL RESULTS

production ceased and/or a stable pressure profile was attained. Throughout this article, the oil saturation at the end of each process refers to remaining oil saturation, but because almost all of the literature mixes remaining and residual oil saturation, residual oil saturation (Sor) was used for experimental process end points in this article.

In this section, first, the experimental results obtained during low salinity waterflooding in tertiary and secondary modes are presented, and then the results from combined low salinity water/polymer injection are displayed. In all experiments, injection continued until 1225


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Figure 3. Oil recovery factor, differential pressure, and injection rate as functions of volume injected for intermediate-wet composite core S3−S4 (tertiary-mode LS injection).

Figure 4. Oil recovery factor, differential pressure, and injection rate as functions of volume injected for strongly water-wet core S11 (secondary-mode LS injection).

Tertiary-Mode Low Salinity Waterflooding. Strongly water-wet composite core S9−S10 and intermediate-wet composite core S3−S4 were chosen to perform tertiary-mode low salinity water injection. The oil recovery profile for this composite core is a typical profile for water-wet systems, with almost no oil being produced (no two-phase production) after breakthrough even when the injection rate was increased (Figure 2). The oil recovery factor at the end of SSW flooding was 51% OOIP, and injection of low salinity water did not change the recovery factor. The relative permeability of the injection water was 0.11 at the end of both SSW and LS flooding, confirming the water-wet conditions of the porous media. The intermediate-wet composite core S3−S4 was flooded with synthetic seawater to establish residual oil saturation conditions, and then tertiary-mode low salinity water was injected to examine the LSE on oil mobilization. The oil recovery factor for this core at SSW breakthrough was about 45% OOIP, and after a long tail (two-phase) production, which is typical for nonwater-wet porous media, the oil recovery factor reached about 64.4% OOIP at the end of SSW flooding. Tertiary-mode LS injection started after SSW injection. No oil production was observed for lower

injection rates. However, marginal oil production (about 0.4% OOIP) was observed at rate of 1 cm3/min (Figure 3), where the final recovery factor reached 64.8% OOIP. The water relative permeabilities at the end of SSW and LS injections were 0.33 and 0.37, respectively, reflecting a less water-wet system than in the previous experiment. The higher recovery factor for core S3−S4 compared to that for strongly water-wet core S9−S10 is in line with previously reported results28 that intermediate-wettability conditions give more oil recovery than strongly water-wet conditions because of low capillary forces. This is because the Amott index for the cores used in this study was very close to zero (Figure 1), and therefore, the contact angle was close to 90° (θ = 90°). Under such conditions, cos θ will have a very low value close to zero, and based on capillary pressure formula, Pc = (2σ cos θ)/r, the capillary forces will be lower than in strongly water-wet porous media, where the contact angle is close to zero and, as a result, the capillary forces reach the highest possible values. For the crude oil−brine−rock system of this study, the obtained results showed no potential for increased oil recovery by tertiary-mode LS flooding under strongly water-wet 1226


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Figure 5. Comparison of oil recovery factor, differential pressure, and injection rate as functions of volume injected for core S11 (secondary-mode LS injection) and core S9−S10 (secondary-mode SSW injection).

Figure 6. Experimental and simulation data for recovery factor and differential pressure of water-wet cores S11 (secondary LS injection, left) and S9−S10 (secondary SSW injection, right).

Figure 7. Estimated (A) capillary pressure and (B) relative permeability curves for cores S11 (secondary-mode LS injection) and S9−S10 (secondarymode SSW injection). (C) Expanded plot for capillary pressure. 1227


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Figure 8. Oil recovery factor, differential pressure, and injection rate as functions of volume injected for intermediate-wet composite core S6−S7 (secondary-mode LS injection).

Figure 9. Comparison of oil recovery factor, differential pressure, and injection rate as functions of volume injected for cores S6−S7 (secondary-mode LS injection) and S3−S4 (secondary-mode SSW injection) .

The capillary pressure (Pc) and water−oil relative permeability curves for core S11 and composite core S9−S10 were estimated by history matching the experimental pressure and production data using the core flood simulator Sendra. The history match of pressure and production data for these cores is presented in Figure 6. Figure 7 shows the estimated capillary pressures and relative permeabilities based on the history match obtained for these cores. This figure indicates that LS injection shifted the wettability of the rock to a more oil-wet state. The Pc curve (Figure 6) shows that, in core S11, both spontaneous and forced imbibition of water are responsible for oil recovery whereas, in core S9−S10, oil is recovered through spontaneous oil imbibition. The relative permeability curves also show more oil wetness for core S11. Composite core S6−S7 under intermediate-wet conditions was used to investigate the LSE in secondary mode. The physical properties and initial saturation conditions of this core were very similar to those of core S3−S4 (Table 4). Low salinity water was injected into this core at initial water saturation (Swi) conditions using the same procedure as before. The oil recovery factor for this core at breakthrough was 51.5% OOIP, compared to 45.2%

conditions and very limited potential for intermediate-wet porous media. Secondary-Mode Low Salinity Waterflooding. Strongly water-wet core S11 and intermediate-wet composite core S6−S7 were used to investigate the LSE in secondary-mode LS flooding. Figure 4 shows the oil recovery, pressure drop across the core, and injection rate as functions of injected pore volume for strongly water-wet core S11 during secondary-mode LS injection. The oil recovery factor for this core at breakthrough was 52.9% OOIP compared to 50.5% OOIP for water-wet core S9−S10, where SSW was injected under initial water conditions. Also, the final oil recovery by secondary LS injection reached 54.3% OOIP, about 3% more than oil recovery in core S9−S10 after SSW flooding. As for core S9−S10, almost no oil production (no two-phase production) was observed after breakthrough, even when the injection rate was increased, a typical behavior for water-wet cores. Figure 5 shows a comparison of the experimental results obtained during secondary-mode LS and secondary-mode SSW injection in strongly water-wet cores S11 and S9−S10, respectively. 1228


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Figure 10. Experimental and simulation data for recovery factor and differential pressure of intermediate-wet cores S6−S7 (secondary-mode LS injection, left) and S3−S4 (secondary-mode SSW injection, right).

Figure 11. Estimated (A) capillary pressure and (B) relative permeability curves for intermediate-wet cores S6−S7 (secondary-mode LS injection) and S3−S4 (secondary-mode SSW injection).

OOIP for core S3−S4 where synthetic seawater was injected under initial water conditions. Also, the final oil recovery reached more than 78% OOIP (Figure 8), leaving a residual oil saturation of 17% PV, whereas the residual oil saturation in core S3−S4 was 28% PV after SSW flooding. The additional oil recovery by LS was about 13% OOIP (10% saturation units) compared to seawater injection. The water relative permeability at the end of LS injection was 0.4 (at Sor = 0.17% PV). Figure 9 shows a comparison of pressure drop and recovery profile for secondary-mode LS and secondary-mode SSW injections for intermediate-wet cores. During the early period of the injection (before breakthrough), the pressure increase in core S6−S7 was greater than that in core S3−S4, which could be related to strong oil mobilization and two-phase flow in porous media. In the later part of the experiments, the higher differential pressure in core S3−S4 compared to that in core S6−S7 was due to the higher residual oil saturation in this core (0.28% PV compared to 0.17% PV). Later breakthrough, which is an indication of improved displacement stability (shock front), and higher oil recovery at breakthrough, were the characteristics of the secondary LS injection in core S6−S7 compared to the secondary SSW injection in core S3−S4. A positive response to direct LS flooding has been observed and reported by others (references have been included) and can now be regarded as a general trend. The explanation of secondary versus tertiary LSE is still not conclusive, but a tertiary LS flood might encounter already trapped oil that might be hard to remobilize, whereas direct LS injection will meet continuous oil and avoid trapping/remobilization of oil. This seems to be a plausible reason for higher oil recovery from direct LS flooding compared to tertiary LS flooding. Comparing secondary highsalinity to secondary low salinity waterflooding in our results, no fines migration was observed, but other mechanisms as discussed

are possible either as single effects or as combined effects of different mechanisms. As for the water-wet cores in this study, the capillary pressure (Pc) and water−oil relative permeability curves for intermediatewet cores S3−S4 and S6−S7 were estimated by history matching of the experimental pressure and production data. The results are shown in Figures 10 and 11. As for the water-wet cores, in this case, the estimated capillary pressure and relative permeability curve also indicated a more oil-wet state when the core was flooded with secondary-mode low salinity water, whereas the end-point permeability (most often reported in the literature) indicated a shift toward more water-wet conditions. The estimated capillary pressure suggests that spontaneous water imbibition was absent during the oil production, as spontaneous water imbibition is responsible for more oil trapping by snap-off events during water flooding. The absence of spontaneous water imbibition and, therefore, the lack or weakness of snap-off events indicates the weakness of trapping mechanisms during secondary-mode LS flooding, where, as a consequence, the oil is produced over the longer period before water breakthrough. Combined LS/Polymer/Linked-Polymer Injection. The goal of this part of experiment was to investigate the possible positive interaction of low salinity water and polymer/linkedpolymer injection as a hybrid EOR process on final oil recovery efficiency. It has been previously reported that high tertiary oil recovery could be obtained by surfactant injection after stabilizing a low salinity environment as surfactant adsorption is reduced in low salinity environments.12 This might also be applicable for anionic polymers, such as hydrolyzed polyacrylamide (HPAM), where the adsorption is strongly dependent on salinity29 and decreases at lower salinities. This could result in a lower loss of polymer from the bulk solution, a longer-lasting favorable mobility ratio, and an improved sweep efficiency. In this study, polymer injection was initiated after low salinity residual oil saturation in both secondary 1229


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Figure 12. Oil recovery profile, differential pressure, and injection rate as functions of volume injected during secondary-mode low salinity-polymer/ LPS injection for intermediate-wet core S6−S7.

Figure 13. Comparison of oil recovery and differential pressure as functions of volume injected during secondary-mode low salinity-polymer injection for cores S6−S7 and S12.

polymer was only 1% OOIP, showing that a favorable mobility ratio is a necessary but not sufficient condition for oil recovery improvement. In intermediate-wet core S6−S7, which was used for secondary-mode LS flooding, after LS injection at initial water saturation (Swi), the core, with a considerably low residual oil saturation of 0.17% PV, was injected with 300 ppm polymer and then 300 ppm LPS at a constant injection rate of 0.1 cm3/min. In this case, the core showed a very encouraging response to polymer flood as is shown in Figure 12. The increased oil recovery was about 12% OOIP. The residual oil saturation was reduced to a very low value of 0.08 PV (9 saturation units reduction in Sor due to polymer injection). Examining the Reproducibility of Increased Oil Recovery by Combined Low Salinity Water/Polymer Flooding. To confirm the reproducibility of increased oil recovery by combined secondary-mode LS/polymer flooding, the experiment was repeated by a second flooding. The intermediate-wet core S12, which previously was used for a wettability test at an oil saturation of 0.5% PV, was flooded with low salinity water to establish residual oil saturation conditions. Then, the core at a residual oil saturation of

and tertiary modes to investigate the possibility of further reductions in Sor. In strongly water-wet core S9−S10 after tertiary LS injection, 300 ppm linked polymer solution (LPS) was injected when the residual oil saturation was 0.38 PV. No more oil production was observed with LPS injection, even though the core experienced a considerably higher pressure differential than during LS injection. Injection of 300 ppm polymer was performed in strongly water-wet core S11 at a residual oil saturation of 0.36 PV after a low salinity environment had been established by secondarymode LS injection. Similarly to core S9−S10, even though the core experienced higher differential pressure during polymer flooding, no reduction in Sor was observed. After tertiary-mode LS injection in intermediate-wet core S3−S4, where the residual oil saturation was 0.28 PV, the core was subjected first to 300 ppm LPS injection and then to 1000 ppm polymer flooding to examine the effect of a highly viscous force in reducing the residual oil saturation. The increased recovery factor from this sequence was about 5% OOIP, and the Sor reduced to 0.24% PV. The increase in oil recovery upon injection of 1000 ppm 1230


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Figure 14. Comparison of oil recovery and residual oil saturation as functions of volume injected during secondary-mode low salinity-polymer injection for cores S6−S7 and S12.

about 0.16% PV was flooded with a 300 ppm polymer solution at an injection rate of 0.1 cm3/min. As for core S6−S7, a significant increase in oil recovery of about 17% OOIP was recorded, and the residual oil saturation decreased to about 0.07% PV. Figures 13 and 14 present a comparison of the differential pressure, recovery factor, and residual oil saturations observed during polymer flooding in cores S6−S7 and S12. The results from these experiments confirm that the increased oil recovery by combined secondary-mode LS/polymer flooding was reproducible under the experimental conditions of this study. As Figure 12 shows, the injection rate was increased stepwise during LS flooding to eliminate or further reduce capillary end effects. Generally, if the differential pressure becomes high during polymer flooding but is lower than the pressure during the bump rate, end effects are unlikely. If the pressure during polymer injection exceeds the bump rate pressure, end effects are possible, but the increase in pressure could also be due to additional oil production (relative permeability effect). Considering the pressure differential during different rate increases and the corresponding oil recovery at each bump in the rate, it was possible to produce some oil from the region affected by capillary end effects. However, according to the differential pressure during polymer flooding, which increased by less than a factor of 2 compared to that during LS flooding at a rate of 1 cm3/min, and comparing the oil recovery during polymer flooding with oil recovery by the LSE when the injection rate was increased, we believe that the majority of oil is produced from better sweep efficiency throughout the core. Furthermore, in other experiments in this study, for example, for core S9−S10, a considerable increase in pressure gave no significant change in residual oil saturation. Therefore, it seems that pressure accumulation is not a necessary condition for increased oil recovery in this study. A summary of the results obtained from different flooding experiments is presented in Table 5. Also, the capillary numbers (Nc) for all experiments at different flow rates and during injection of different fluids are reported in Table 6. The capillary number at which residual oil saturation tends to drop with increasing capillary number is known as the critical desaturation number or critical capillary number (Ncc) and is dependent on wettability states of the porous media. From the literature,30 the critical capillary numbers for water-wet and intermediate-wet Berea sandstone are ∼10−5 and ∼10−4, respectively. Therefore, Table 6 shows that the capillary numbers during all experiments,

Table 5. Summary of the Experimental Results PV Soi RFLS SorLS RFf Sorf ΔRFP Krow at core ID (mL) (% PV) (%OOIP) (% PV) (% OOIP) (% PV) (% OOIP) SorLS S9−S10 S11 S3−S4 S6−S7 S12

25.01 17.77 25.80 25.39 15.18

78 78 79 78 50

51.0 54.3 64.8 78.1 68.7

38 36 28 17 16

51.0 54.3 70.1 89.8 85.8

38 36 24 8 7

0 0 5 12 17

0.11 0.09 0.37 0.40 0.36

especially during polymer flooding, were below the critical desaturation number.

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DISCUSSION Secondary- versus Tertiary-Mode LS Flooding. The design of an LS flooding process might be influenced by when the injection was started. Previous studies have been mostly focused on examining increased oil recovery by LS injection in tertiary mode, where the invading low salinity fluid is injected at residual oil saturation left behind after high-salinity water flooding. Some researchers have investigated the oil recovery efficiency of low salinity water as an invading fluid in secondary mode (at initial water saturation). Zhang and Morrow6 compared the oil recovery obtained by LS flooding in secondary and tertiary modes upon changing the injection brine composition and concluded that, in the case of a positive response, injection of LS improves oil recovery for both secondary and tertiary modes but sometimes for only one or the other. Secondary-mode LS injection and the effect of wettability on oil recovery was investigated by Ashraf et al.7 They reported a higher oil recovery for secondary-mode LS injection than for high-salinity brine injection under different initial wettability states. They also found the highest reduction in residual oil saturation by LS injection under water-wet conditions. In research performed by Rivet et al.,8 tertiary-mode LS did not produce incremental oil recovery. They observed improved ultimate oil recovery by secondarymode LS injection only in intermediate-wet systems, whereas water-wet systems did not show any recovery by secondary LS flooding. Other researchers also reported better recovery response for secondary- compared to tertiary-mode LS injection.9,31 The results of this experimental work indicate that an early start to LS injection is beneficial for oil recovery. Under the reported experimental conditions of this study, during tertiarymode LS injection, no oil recovery was observed for strongly 1231


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Table 6. Capillary Numbers (Nc) for Different Experiments at Different Flow Rates of Different Displacing Fluids injection rate (cm3/min)

S3−S4

0.1 0.2 0.5 1.0

1.02 × 10−7 2.04 × 10−7 5.10 × 10−7 1.02 × 10−6

− − − −

1.02 × 10−7 2.05 × 10−7 5.11 × 10−7 1.02 × 10−6

− − − −

− − − −

0.1 0.2 0.5 1.0

6.28 × 10−8 1.26 × 10−7 3.14 × 10−7 6.28 × 10−7

6.27 × 10−8 1.25 × 10−7 3.13 × 10−7 6.27 × 10−7

6.30 × 10−8 1.26 × 10−7 3.15 × 10−7 6.30 × 10−7

6.18 × 10−8 1.24 × 10−7 3.09 × 10−7 6.18 × 10−7

6.18 × 10−8 − 3.09 × 10−7 6.18 × 10−7

0.1 0.2 0.3 0.4

1.34 × 10−7 2.68 × 10−7 4.03 × 10−7 5.37 × 10−7

1.58 × 10−7 − − −

1.35 × 10−7 − − −

1.56 × 10−7 − − −

1.56 × 10−7 − − −

S6−S7

S9−S10

S11

S12

SSW

LS

polymer/LPS

difference in ionic strength of LS and connate water) is likely and could lead to destabilized oil layers (movable oil). The results obtained in this study show that the initial wettability state of a porous medium is a key factor in the waterflooding efficiency of LS injection and that more intermediate-wet cores give a better response; however, this factor alone cannot explain the mechanism(s) behind the success or failure of LS injection. It is commonly believed that wettability alteration toward a more water-wet state is the reason for oil mobilization and production. However, there are also some reports of shifting to a more oil-wet state (this study and article by Fjelde et al.34). The discussion here is that, if the wettability alteration is a mechanism for the LSE, it is not always toward a more water-wet state (as most researchers have reported), but it could also be toward a more oil-wet (less water-wet) state as well. The mechanism leading to this effect is an increase in the adsorption of organic components with salinity reduction, because of the competition between the different active species toward the negative sites of the clay. Thus, a negative salinity gradient will increase the adsorption of organic material onto the clay. This will shift the wettability to lower water wetness.22 Adhesion mapping studies by Buckley et al.35 also showed that there are regions of stability and instability of water films, where nonadhesion or adhesion of crude oil components onto the rock surface could be observed, depending on brine salinity. This adhesion mapping shows that, under low salinity conditions, water films are unstable and, therefore, adhesion of crude oil components could alter the wettability to a less water-wet state. Combined Low Salinity Water/Polymer Injection. The results of this study indicate that combined LS/polymer flooding containing a low polymer concentration of 300 ppm could mobilize residual oil in porous media and further increase the oil recovery factor. The concentration of polymer solutions used in this hybrid EOR process (300 ppm) is low enough from the point of view of their practical applicability (injectivity), because the viscosity of such solutions is only 2.6 cP compared to a water viscosity of 1 cP at room temperature. The increased oil recovery by LS/polymer flooding was examined for reproducibility by a second flood, and the results were in line with those of the primary experiments. The results also suggest that, although polymer injection could mobilize residual oil after tertiary-mode LS flooding, higher oil recovery by polymer injection occurs when the low salinity environment is established at initial water saturation (Swi) rather than Sor (i.e., when the

water-wet cores, and only very limited oil was recovered from intermediate-wet cores. Low salinity water injection as a secondary recovery mode was promising. Both water-wet and intermediate-wet cores showed positive response for this flooding mode. Unlike the observations by Rivet et al.,8 this study showed increased oil recovery of about 3.3% OOIP in strongly water-wet cores by secondary-mode LS injection compared to secondary-mode SSW injection (Table 5). However, a substantial increase in oil recovery by secondary LS injection was obtained in intermediate-wet cores, where the oil recovery was 13% OOIP more than that of secondary SSW injection in intermediate-wet cores. The results showed that the reduction in residual oil saturation by secondary LS injection is higher for intermediate-wet cores than for strongly water-wet cores. This contrasts with the observations by Ashraf et al.,7 who found a higher reduction in Sor under water-wet conditions. The pressure profiles during all experiments, especially during LS flooding, were stable, and no fines production was observed. This indicates that microscopic flow diversion by fines migration was not a key contributing mechanism to the increased oil recovery by LS injection in our cases. This is in accordance with other observations in the literature, among them those of Boussour et al.18 and Cissokho et al.32 The reason for high oil recovery in secondary-mode compared to tertiary-mode LS flooding might be effective trapping31 of oil clusters during high-salinity water injection before initiation of tertiary-mode LS flooding. Referring to Figure 1, the wettability of the cores during aging with crude oil was changed to an intermediate-wet state, where possibly the larger pores were oil-wet and the smaller pores remained water-wet.33 During highsalinity water injection, the invading fluid first occupies smaller pores through film flow, which might lead to snap-off oil clusters in the larger pores. This might limit the continuity of oil through porous media and increase the chance of oil trapping. Tertiarymode LS would pass through “open-to-flow” channels and pores, in which case the pores with trapped oil would be bypassed by low salinity water. No contact with low salinity water would prevent any reaction of low salinity water with pore elements (pore throats and pore walls) to mobilize trapped oil. Oil mobilization in secondary-mode LS is possible by maintaining film continuity and allowing for fewer snap-off events in a weaker water-wet state for direct LS injection. Also, multicomponent ion exchange together with expanding double layer (due to the 1232


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Figure 15. Comparison of propagation of 300-ppm polymer/LPS solution through water-wet and intermediate-wet sandstone cores based on the differential pressure at each wettability state.

enhanced oil recovery reported by Mohammadi and Jerauld,39 as well as the experimental studies by Kozaki.40 Mohammadi and Jerauld39 demonstrated that addition of polymer to a low salinity aqueous base fluid enhances recovery efficiency in both secondary and tertiary modes, but secondary mode gives better timing of oil recovery. They attributed most of the benefit of the polymer to an improvement in fractional flow behavior. The difference between this experimental work and the simulation study by Mohammadi and Jerauld39 is that they injected a low salinity polymer solution at Swi (in secondary mode) or after high-salinity residual oil saturation, whereas in the current work, first low salinity water was flooded in secondary or tertiary mode to establish a low salinity environment in the porous media and then polymer solution was injected.

polymer solution is injected after residual oil saturation established by secondary-mode LS flooding). The reason why combined LS/polymer injection produces more oil can be attributed to an improvement of the stability of the LS flood by addition of polymer,36 which improves the efficient banking of oil through a favorable mobility ratio and/or inaccessible pore volumes, thereby increasing the displacement efficiency. The inaccessible pore volume (IPV) indicates the portion of the pore volume for which the entrance radii of the pore elements are smaller than the polymer particles (especially when a high-molecular-weight polymer is used). This volume is mostly occupied by the irreducible or connate water. Inaccessibility of this volume to the polymer would result in the absence of a highly mobile connate water bank, and therefore, the polymer solution would not displace the connate water.37 The consequence is a better sweep efficiency of the polymer solution and increased oil recovery. Moreover, the results of this study show that the initial wettability state of a porous medium is important for the combined LS/polymer effect, where the strongly water-wet cores did not display any reduction in residual oil saturation as a result of this combined process, despite the considerably high differential pressure experienced in the system. The differential pressure in intermediate-wet cores was much lower than that in water-wet cores, as presented in Figure 15. This figure shows the differential pressure across water-wet and intermediate-wet cores during first three pore volumes of polymer flooding. The higher pressure buildup in water-wet cores could possibly be related to higher adsorption/retention of polymer on waterwet rock surfaces compared to intermediate-wet media. During a polymer flood in an intermediate-wet reservoir, the injected polymer will interact with significant portions of oil-wet rock. In this case, it is possible that rock wettability will have a considerable effect on polymer adsorption.38 The adsorption of crude oil components reduces the adsorption sites on rock surface, and therefore, the tendency of polymer molecules to interact with the rock surface is decreased. Higher polymer adsorption on water-wet rock surfaces results in a poor sweep efficiency of polymer solution as a result of retention in porous media and intensification of the trapping of oil in the blocked pores. The increased oil recovery from combined low salinity water/ polymer flooding in this study is in line with the simulation study of the benefit of combining polymer with low salinity water for

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CONCLUSIONS Injection of low salinity water (LS) was found to increase oil recovery compared to injection of seawater even in the water-wet state, but injection of LS after high-salinity water gave no change in Sor in the water-wet state. This behavior can be explained by effective trapping (snap-off of oil clusters in larger pores) during seawater injection. The initial wettability state of a porous medium seems to be a key factor in the waterflooding efficiency of LS injection as more intermediate-wet cores give a better response. Wettability alteration by low salinity can be interpreted as a shift toward either more water-wet or more oil-wet conditions, possibly depending on the wettability indicator detected. The derived capillary pressure and relative permeability in our experiments indicate a shift toward a more oil-wet state. Wettability shift in our experiment is very uncertain, and other possible factors such as clay swelling, internal fines migration, and residual oil distribution might all affect the differential pressure and production in a manner to be interpreted as an alteration in wettability. A stable pressure profile during LS flooding and the lack of fines production indicate that, in our cases, microscopic flow diversion by fines migration is not a key mechanism and multicomponent ion exchange together with an expanding double layer is likely and could lead to destabilized oil layers (movable oil). Combined low salinity water/polymer flooding was found to lead to very high total oil recovery, probably because of the 1233


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(5) Webb, K. J.; Black, C. J. J.; Edmonds, I. J. Low salinity oil recovery: The role of reservoir condition corefloods. Presented at the 13th European Symposium on Improved Oil Recovery, Budapest, Hungary, Apr 25−27 2005. (6) Zhang, Y.; Morrow, N. R. Comparison of secondary and tertiary recovery with change in brine composition for crude oil/sandstone combinations. Presented at the 2006 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, Apr 22−26, 2006; Paper SPE 99757. (7) Ashraf, A.; Hadia, N. J.; Torsæter, O.; Tweheyo, M. T. Laboratory investigation of low salinity water flooding as secondary recovery process: effect of wettability. Presented at the SPE Oil and Gas India Conference and Exhibition, Mumbai, India, Jan 20−22, 2010; Paper SPE 129012. (8) Rivet, S. M.; Lake, L. W.; Pope, G. A. A core flooding investigation of low salinity enhanced oil recovery. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, Sep 19−22, 2010; Paper SPE 134297. (9) Gamage, P.; Thyne, G. Comparison of oil recovery by low salinity water flooding in secondary and tertiary recovery modes. Presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, Oct 30−Nov 2, 2011; Paper SPE 147375. (10) Mahani, H.; Sorop, T. G.; Ligthelm, D.; Brooks, A. D.; Vledder, P.; Mozahem, F.; Ali, Y. Analysis of field responses to low salinity water flooding in secondary and tertiary mode in Syria. Presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition, Vienna, Austria, May 23−26, 2011; Paper SPE 142960. (11) Winoto, W.; Loahardjo, N.; Xie, X.; Yin, P.; Morrow, N. R. Secondary and tertiary recovery of crude oil from outcrop and reservoir rocks by low salinity water flooding. Presented at the Eighteenth SPE Improved Oil Recovery Symposium, Tulsa, OK, Apr 14−18, 2012; Paper SPE 154209. (12) Alagic, E.; Skauge, A. Combined low salinity brine injection and surfactant flooding in mixed-wet sandstone cores. Energy Fuels 2010, 24 (6), 3551−3559. (13) Skauge, A. Microscopic diversion: A new EOR technique. Presented at the 29th IEA Workshop & Symposium, Beijing, China, 2008. (14) McGuire, P. L.; Chatham, J. R.; Paskvan, F. K.; Sommer, D. M., Carini, F. H. Low salinity oil recovery: an exciting new EOR opportunity for Alaska’s North Slope. Presented at the 2005 SPE Western Regional Meeting, Irvine, CA, Mar 30−Apr 1, 2005; Paper SPE 93903. (15) Lager, A.; Webb, K. J.; Black, C. J. J.; Singleton, M.; Sorbie, K. S. Low salinity oil recoveryAn experimental investigation. Presented at the International Symposium of the Society of Core Analysts, Trondheim, Norway, Sep 12−16 2006. (16) Sorbie, K. S.; Collins, I. R. A proposed pore-scale mechanism for how low salinity water flooding works. Presented at the 2010 SPE Improved Oil Recovery Symposium, Tulsa, OK, Apr 24−28, 2010; Paper SPE 129833. (17) Liegthelm, D. J.; Gronsveld, J.; Hofman, J. P.; Brussee, N.; Marcelis, F.; van der Linde, H. A. Novel waterflooding strategy by manipulation of injection brine composition. Presented at the EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, Jun 8−11, 2009; Paper SPE 119835. (18) Boussour, S.; Cissokho, M.; Cordier, P.; Bertin, H.; Hamon, G. Oil recovery by low salinity brine injection: Laboratory results on outcrop and reservoir cores. Presented at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Oct 4−7, 2009; Paper SPE 124277. (19) Zhang, Y.; Xie, X.; Morrow, N. R. Waterflood performance by injection of brine with different salinity on reservoir cores. Presented at the SPE Annual Technical Conference and Exhibition, Anaheim, CA, Nov 11−14, 2007; Paper SPE 109849. (20) Pu, H.; Xie, X.; Yin, P.; Morrow, N. R. Application of coalbed methane water to oil recovery by low salinity waterflooding. Presented at the 2008 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, Apr 20−23, 2008. (21) Cissokho, M.; Boussour, S.; Cordier, P.; Bertin, H.; Hamon, G. Low salinity oil recovery on clayey sandstone: Experimental study.

combined effects of this hybrid EOR process. The polymer concentration was low and gave only a small change in mobility ratio. The oil recovery by polymer injection was improved significantly in the case where the low salinity environment was established at initial water saturation (Swi) rather than Sor.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors acknowledge the Norwegian Research Council (NFR) for financial support.

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ABBREVIATIONS D = core diameter (cm) EOR = enhanced oil recovery HPAM = hydrolyzed polyacrylamide IFT = interfacial tension (mN/m) Ko = permeability to oil (mD) Kr = relative permeability Krow = oil relative permeability to water Kw = permeability to water (mD) L = core length (cm) LPS = linked polymer solution LS = low salinity water LSE = low salinity effect Nc = capillary number Ncc = critical capillary number OOIP = original oil in place (mL) ppm = parts per million (mg/kg) PV = pore volume (mL) RF = recovery factor (%OOIP) RFf = final recovery factor (%OOIP) RFLS = recovery factor at the end of low salinity water injection (%OOIP) Soi = initial oil saturation (%) Sor = residual oil saturation (%) Sorf = final residual oil saturation (%) SorLS = residual oil saturation at the end of low salinity water injection (%) Swi = initial water saturation (%) SSW = synthetic seawater TDS = total dissolved solids XRD = X-ray diffraction ΔRFP = incremental recovery factor by polymer injection

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REFERENCES

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