Article pubs.acs.org/EF
Can Lowering the Injection Brine Salinity Further Increase Oil Recovery by Surfactant Injection under Otherwise Similar Conditions? Annette Meland Johannessen† and Kristine Spildo*,‡ †
Center for Integrated Petroleum Research, Uni Research AS, Allégaten 41, 5006 Bergen, Norway Department of Chemistry, University of Bergen, Allégaten 41, 5006 Bergen, Norway
‡
ABSTRACT: It is well-established that injecting water with significantly lower salinity than the formation water salinity may give increased oil recovery. Although less well studied, the observed low-salinity effect has drawn attention to possible benefits from combining low-salinity water with traditional enhanced oil recovery techniques, such as surfactant, polymer, alkali, etc., to make the overall recovery process more efficient. Surfactant injection, for example, reduces the interfacial tension (IFT) between the injected surfactant solution and the oil, thus mobilizing capillary trapped oil and/or reducing the tendency for capillary trapping. The majority of literature on the topic of low salinity and surfactant flooding primarily addresses one or the other. This study, however, compares the combined effect of reduction in IFT and low-salinity conditions to the effect of a sole reduction in IFT on oil recovery in intermediate-wet Berea sandstone cores. We find that reductions in residual oil saturation, at similar capillary numbers and phase behavior conditions, are higher for the low-salinity surfactant injection experiments compared to regular surfactant injection experiments. This strongly indicates that there is a combined effect of IFT reduction and low salinity on recovery compared to that from a reduction in IFT alone.
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INTRODUCTION Injection of low-salinity (LS) water has, in the past decade, received attention because of increased recovery compared to conventional high-salinity (HS) or seawater (SW) flooding.1−6 This has been referred to as the low-salinity effect (LSE).7 Although numerous crude oil/brine/rock (COBR) combinations have been involved in the investigation of mechanisms responsible for the LSE, they are yet to be fully understood. Even so, several authors have attempted at defining an upper limit above which no LS effect is observed (see, e.g., the study by Sheng8 and references cited therein). Sheng8 proposed an upper limit for injection brine salinity at 10−25% of connate water salinity to obtain a LSE based on his summary of available laboratory and field data. In line with this, Morrow and Buckley7 stated that the LSE had been observed for brine compositions up to 5000 ppm. On the other hand, Rezaeioust et al.9 reported increased recovery when flooding a core containing 25 000 ppm of formation water of pure CaCl2 with 40 000 ppm of NaCl solution with the same ionic strength. Defining limits for when changes in brine composition will and will not give rise to an increase in recovery is therefore not unambiguous. However, with respect to cases where the design is to use a dilution of the connate brine as the injection fluid, there seems to be a general consensus that salinities needs to be significantly reduced relative to the connate brine salinity to observe a LSE (see, e.g., studies by Morrow and Buckley7 and Sheng8 and references cited therein). Tang and Morrow5 identified the presence of clay, connate water, and mixed wettability conditions as necessary conditions for the LSE. On the basis of this, mechanisms giving rise to destabilization and mobilization of oil initially adsorbed to the rock surface have been suggested. Such mechanisms include expansion of the electric double layer at the mineral surfaces © 2014 American Chemical Society
because of invasion of brines with lower salinity, multiple ion exchange (MIE) with cations in clay structures with adsorbed oil, and local increase in pH at the clay−water interface by ion exchange with cations in clay.9−11 Still, many sandstone investigations fulfilling these conditions have shown negligible response to LS injection. Nasralla et al.11 suggested that the absence of the LSE in tertiary recovery mode could be due to the absence of a continuous oil film. In this case, the repulsive forces between the charged brine−mineral and oil−brine interfaces, caused by a lowering in injection water salinity, are not strong enough for the trapped oil to be swept by the imposed flow. If this is the case, the benefit from the LS water can only be observed in combination with other methods. Thus, the observed LSE has drawn attention to possible benefits from combining LS water with traditional enhanced oil recovery (EOR) techniques, such as surfactant, polymer, alkali, etc., to make the overall recovery process more efficient. Surfactant injection reduces the interfacial tension (IFT) between the injected surfactant solution and the oil. Winsor12 described surfactant/oil/water microemulsions as type I (lower phase, oil in water), type II (upper phase, water in oil), and type III (middle phase, oil and water in a middle-phase microemulsion). Traditionally, surfactant solutions are tailored to reach ultralow IFT values (90%, demonstrating the process potential. While continuous surfactant injection shows the process potential, it is not a practical strategy suited for field implementation. The present paper therefore uses a polymersupported slug injection strategy, which is more realistic with respect to field injection cases. Further, for a more direct comparison of the combined effect of IFT reduction and LS on recovery compared to what is expected from a sole reduction in IFT, the processes are compared at similar phase behavior (Winsor I) and IFTs. In addition, in situ saturation monitoring by X-ray scanning was performed to study potential differences in saturation development between HS and LS cases.
(1)
where u, μ, and σ are the Darcy velocity, viscosity of the displacing fluid, and IFT between the oil and displacing fluid, respectively. The experimentally observed relationship between residual oil and Nc is referred to as the capillary desaturation curve (CDC), and the capillary number at which the residual oil saturation starts to decrease is the critical capillary number, Ncc. The forces responsible for retaining oil in a porous media are influenced by parameters such as permeability, pore size, pore size distribution, wettability, saturations, fluid distribution, and saturation history.18 CDCs can be obtained by displacement processes of either continuous oil or residual oil.19 For displacement of residual oil, the experiment starts at residual oil saturation established by secondary flood (Sorw). The capillary number is then increased incrementally in steps, waiting for the production to cease at one step before proceeding to the next. Each increment yields a data point, and thus, one experimental run provides the full CDC.17 For displacement of continuous oil on the other hand, Soi is re-established each time Nc is increased; thus, several runs are required for the full CDC.14 It can be noted that highsaturation connected, continuous fluid is more readily recoverable than the disconnected fluid remaining after a flood. During displacement of a high-saturation connected bank, Nc required to prevent trailing of oil being cut off from the oil bank is less than Nc required to mobilize oil once it is capillary-trapped.19 However, after residual oil has been reduced by about 50% of its initial value, the CDC relationships for the continuous oil and discontinuous oil become almost indistinguishable.14,19 In a reservoir application, because of delayed transport of surfactant caused by retention, the waterfront will propagate faster than the surfactant front. Consequently, flooding from Soi will not take place. CDC correlations have been conducted by displacing either the wetting phase or the non-wetting phase.14−17,19−21 Gupta and Trushenski15 found that the displacement of the wetting phase requires a Nc of about one order of magnitude higher than that required to displace the non-wetting phase. When it comes to a mixed-wet medium, the CDC is found to lie in between the curves for strongly oil-wet and strongly water-wet media. Further, CDCs for mixed-wet media show a more gradual decrease in residual oil saturation and a less pronounced Ncc.22 It is established that two essential criteria must be met for an economically viable recovery by surfactant flooding. These are (i) ultralow IFT between surfactant solution and residual oil
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EXPERIMENTAL SECTION
Fluids. The ion concentrations in parts per million (ppm) for the original SW brine as well as dilution factors for the brines used in the core flooding experiments are listed in Table 1. The original SW brine was diluted with distilled water to obtain the desired ion concentrations. The choice of LS brine was based on earlier LSS experiments.23 The HS brine concentrations, however, were tuned to obtain the desired surfactant phase behavior (Winsor I) and IFT, under the constraint that they were significantly higher than those commonly associated with a possible LSE. In each experiment, the same brine was used throughout the course of the experiment, i.e., both during the water flooding and as a solvent for the surfactant formulation and the drive polymer. The properties of the different oil phases used in this study are listed in Table 2, including the acid number (AN) for crude oil B. All 6724
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Table 2. Oil Properties at 22 °C oil
AN (mg of KOH/g)
μ (mPa s)
ρ (g/cm3)
crude B crude BM1 (crude B + 23% xylene) crude BM2 (crude B + 20% xylene + 20% iododecane)
2.96
93 5.4 4.9
0.868 0.942
Core Preparation. Five Berea cores were dried and mounted in core holders with an overburden pressure of 20 bar. They were vacuumed, saturated with synthetic SW, and equilibrated for 1 week. Reservoir formation brines typically contain both mono- and divalent ions, as is the case for the SW composition used here. Thus, to be representative of a general field case, any brine formulation containing both mono- and divalent ions can in principle be used. However, for a field-specific study, a brine composition representative of the field formation water would be the natural choice. Still, for the more general study presented here, SW is used to represent the formation brine. The three cores that were used for X-ray scanning were initially mounted in composite core holders to scan the cores in dry conditions as well as 100% water-saturated conditions. PV, porosity (ϕ), and absolute permeability to water (Kw) were measured before the cores were drained to initial water saturation (Swi). Core properties are listed in Table 3. Clay types and contents for a typical core from the batch of Berea used are listed in Table 4.
of the cores were initially saturated with crude B, which was used for aging. Because of the viscous nature of this crude oil, it was replaced by a modified crude oil prior to conducting the flooding experiments. This was done to avoid viscous instabilities. Further, to improve the contrast in the X-ray signal between oil and water, iododecane was also added to the oil phase in the cores that were imaged by X-ray scanning. The same oil phase was used in the core flooding sequences, phase behavior, and IFT studies. As stated earlier, the objective was to study the combined effect of IFT reduction and LS on recovery compared to what is expected from a sole reduction in IFT. For this purpose, the HS and LS processes need to be compared at similar phase behavior (in this case, Winsor I) and IFTs. This is not easily done using a single surfactant and cosolvent. As a result, two types of surfactants were used to design the surfactant formulations used in the flooding experiments: an alcohol propoxy sulfate (APS) and an internal olefin sulfonate (IOS), both supplied by Shell Chemicals. The alcohol APS is a branched C12−C13 hydrocarbon chain with 7 propylene oxide (PO) groups (32% surfactant activity). This was used in combination with an IOS with a C15−C18 hydrocarbon chain (33% surfactant activity). Co-solvents used were either isoamyl alcohol (IAA) or secondary butanol (SBA). The core flooding experiments were designed as slug injection [0.5 pore volume (PV)] experiments, with a total surfactant concentration of 0.5 wt % and a 1:1 surfactant/co-solvent ratio. The total surfactant concentration was approximately 80% of the amount of surfactant used in a previous study employing a continuous injection process.23 Further, in comparison to the experiments with continuous injection, the surfactant concentration was increased from 0.2 to 0.5 wt %, because some studies indicate that surfactant use is better at a higher surfactant concentration in a small PV slug.27,28 The surfactant slug was followed by polymer support, consisting of partially hydrolyzed polyacrylamide from SNF (Flopaam 3630S) added to the brine phase. The amount of polymer added was chosen by requiring a viscosity of close to 10 cP with the relevant brine phase, at a shear rate of 10 s−1. This resulted in added polymer concentrations of between 600 ppm (LS) and 1200 ppm (HS), depending upon the brine composition. Phase Behavior Screening. Static phase behavior test samples were prepared in specially designed, graduated pressure tubes. They were prepared by adding a fixed amount of surfactant, co-surfactant, and co-solvent to diluted SW brines of varying salinities and mixed with the appropriate oil at ambient temperature. A total surfactant concentration of 3 wt % was used in all tests, with an equal amount of co-solvent added. The surfactant/co-surfactant ratio was, however, varied. A higher surfactant concentration was used in the phase behavior screening than in the flooding experiments and IFT measurements. This was done to achieve higher solubilization and, thus, more easily detectable phase transitions. Solubilization parameters (SPi) were obtained by measuring the phase heights in the samples after equilibration. Optimal salinity (S*) is the salinity at which the middle microemulsion phase contains equal volumes of oil and water; i.e., SPw = SPo = SP* = solubilization parameter at optimum (see, e.g., the study by Healy et al.13). Thus, optimal salinity S* was determined as the point where SPw = SPo when plotted as a function of salinity. IFT Measurements. IFT measurements were performed using the spinning drop method for values below 1 mN/m. Measurements were made on both pre-equilibrated solutions and solutions obtaining equilibration while spinning to ensure that equal IFT values were obtained by both methods. For higher IFT values, i.e., for BM1 and BM1 against brine without added surfactant, the pendant drop method was used. All measurements were performed at ambient temperature.
Table 3. Core Properties core
length (cm)
Kw (mD)
φ (%)
PV (mL)
Swi
LS1 LS2 HS1 HS2
14.932 10.290 10.179 10.266
320 360 290 330
21.6 21.8 22.7 21.3
37.07 25.14 26.04 24.50
0.31 0.23 0.36 0.26
Table 4. Clay Type and Content for a Typical Core from the Batch of Berea Used clay type
content (mass %)
kaolinite chlorite smectite mica
3.2 1.7 0.0 3.0
To achieve representative Swi values, drainage was performed using highly viscous oil. Because of the viscous nature of crude B (see Table 2), cores LS1 and HS1 were drained directly with crude B. However, because of decreasing availability of crude B, LS2 and HS2 were drained with Marcol 152, which was later replaced by crude B for aging. Because of the temperature limit of composite core holders of 100 °C, Hassler core holders were used during aging. The cores were aged for 2 weeks at 110 °C. After aging, the modified versions of crude B, BM1 (no in situ saturation measurements) or BM2 (in situ saturation measurement), replaced the aging oil. All core floods were performed at ambient temperature. In Situ Saturation Monitoring. The in situ fluid saturations were determined using an X-ray scanning technique and a semi-log interpolation method based on Lambert’s law. The horizontal scan range is approximately 3 m and is shielded with lead, except where the sample is located. The detector is also surrounded by a lead shield. The detector system is mounted on a trolley, which is moved by a step motor along the sample. The X-ray data are collected by moving the X-ray generation tube, collimator, and a detector as a single unit in the horizontal direction of the test sample from the production to the injection end (see Figure 1). When starting a scan, the lead shutter opens, emitting X-rays from a 70 kV, 0.1 mA MiniFocus Tungsten target source. A detector measures the intensities of the X-rays passing through the sample. After the predefined count interval of 3 s, the X-ray device moves to the next position. Intensities are measured every 0.5 cm. 6725
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The oil saturation calculations for each position in each scan were computed by a source code in MATLAB.
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RESULTS AND DISCUSSION Phase Behavior and IFT. The composition of the surfactant slugs were decided on the basis of phase behavior
Table 5. Phase Behavior Results for Different APS/IOS Ratios, Co-solvents, and Oil Compositions at Ambient Temperaturea Figure 1. X-ray saturation scanner layout.25
The material the X-rays pass through from source to detector attenuates them. Because every material has a different power to absorb X-rays, the reduction in intensity of an X-ray beam as it passes through a core depends upon the fluids present. To improve the accuracy of the saturation determination in this study, the oil phase was doped with iododecane, which enhances the attenuation contrast between the oil and water phase. To compute the oil saturation during a flooding process, reference scans are required before a flooding experiment is initiated. The reference scans are ideally conducted when the core is dry, when the core is 100% saturated with brine, and when the core is 100% saturated with oil. Any partial saturation can then be calculated on the basis of the interpolation between the 100% scans. Scans at 100% oil saturation are usually obtained after the flooding experiment is finished; however, these scans were not conducted in this study because of difficulties cleaning and removing polymer completely from the core. Therefore, scans at Swi were used instead, where the experimental Swi is included in eq 2. In this case, the uncertainty in the calculated saturations comes from the uncertainty from the scans as well as from the material balance. The oil saturation at Swi at each measured point is given by distributing the average oil saturation from the material balance according to the difference in counts between the 100% watersaturated scans and the scans at Swi (see eq 2).27,28
ln So, Swi = So,̅ Swi −
I100% ̅ water IS̅ wi
ln
− ln
ln I − ln I100% water ln ISwi − ln I100% water
oil phase, crude
S*, diluted SW (ppm)
SP*
3:1 3:1 1:0 2:5 1:1
SBA SBA IAA SBA IAA
BM1 BM2 BM2 BM1 BM2
15301 27475 7347 54000 17205
12.6b 13 c 11 10.5
A 1:1 surfactant/co-solvent ratio and a total surfactant concentration of 3 wt % were maintained in all experiments. bData from ref 23. cSP* was not calculated because of a narrow salinity window. Only one tube displayed three phases for this system at the salinity listed in the table.
Table 6. Overview over Surfactant Formulations, with Varying APS/IOS Ratios and Type of Co-solvent Used in the Different Core Flooding Experimentsa APS/IOS ratio
co-solvent
oil phase, crude
diluted SW (ppm)
IFT (mN/m)
core
3:1 1:0 2:5 1:1
SBA IAA SBA IAA
BM2 BM2 BM1 BM2
2549 2549 25866 15301
0.12 0.025 0.06 0.015
LS1 LS2 HS1 HS2
a
The corresponding oil/water IFTs are also shown for relevant combinations of brine and crude oil phases. A 1:1 surfactant/cosolvent ratio and a total surfactant concentration of 0.5 wt % were maintained in all experiments.
studies and IFT measurements. In line with the objectives of the paper, the criteria for selecting suitable surfactant formulations for both LS and HS conditions was (i) that they displayed a Winsor I phase behavior and (ii) that they had sufficiently low IFTs with the relevant crude oil and brine phases. By HS and LS conditions, we mean brine concentrations well above and below 5000 ppm, respectively. One should be careful in defining absolute limits for when the LSE is present or not, given that the mechanisms behind are
(2)
In eq 2, I is the intensity counted by the detector and the subscripts denote the saturation state of the core. At each measured point during the flooding experiment, the oil saturation is given by eq 3. So = So, Swi
co-solvent
a
I100% water IS wi
I100% ̅ water IS̅ wi
APS/IOS ratio
(3)
Figure 2. (Left) Solubilization parameters and (right) phase ratio as a function of salinity for the phase behavior scan of 3 wt % 3:1 APS/IOS, 3 wt % SBA, and crude BM2 at ambient temperature. 6726
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Figure 3. Oil recovery (% OOIP), differential pressure (mbar), and WBT as a function of injected PV for core LS1 at ambient temperature.
Figure 4. Oil recovery (% OOIP), differential pressure (mbar), and WBT as a function of injected PV for core LS2 at ambient temperature.
not yet fully understood. In this study, we nonetheless chose 5000 ppm as a limit between LS and HS conditions based on the literature survey by Buckley and Morrow.7 Meeting these criteria required mixing different ratios of the APS and IOS surfactants as well as varying the polarity of the co-solvent. Further, for the HS experiments, two different brine salinities in the HS regime had to be used because of differences in the oil properties in the two experiments. In a previous study, we used SW dilutions with a total dissolved solids (TDS) content of 2500 ppm (LS) and 15 000 ppm (HS), respectively.23 Thus, these were the brine compositions of choice in the present study as well. As will be discussed later, however, to achieve a low enough IFT with crude BM1, a higher salinity brine (26 000 ppm) had to be used for this experiment (core HS2). Phase behavior experiments were first performed to identify surfactant formulations, which could give rise to Winsor I phase behavior and low IFT at both HS and LS conditions. An
overview over the resulting formulations is given in Table 4, with the corresponding plot of solubilization parameters and phase ratios as a function of salinity for the 3:1 formulation used in core LS1 given in Figure 2. Values of S* and the corresponding optimal solubilization parameter, SP*, were obtained from the individual plots (similar to Figure 2) as the x- and y-axis values, respectively, when SPw = SPo. Both values are listed in Table 5. As expected, removing the more hydrophilic IOS surfactant from the formulation decreases S*, i.e., makes the surfactant formulation more hydrophobic. The same effect is seen when SBA is substituted with IAA and the ratio between APS and IOS changed from 3:1 to 1:1. Further, it can be noted that 3:1 APS/IOS with SBA was used in a previous study with crude BM1.23 With crude BM1, S* was at 15 000 ppm diluted SW, as opposed to around 27 000 ppm with crude BM2. S* is known to increase with an increasing hydrophobic character of the oil phase.29 Thus, this increase in S* from BM1 to BM2 indicates a 6727
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Figure 5. Oil recovery (% OOIP), differential pressure (mbar), and WBT as a function of injected PV for core HS1 at ambient temperature.
Figure 6. Oil recovery (% OOIP), differential pressure (mbar), and WBT as a function of injected PV for core HS2 at ambient temperature.
using different surfactant formulations, as illustrated by Table 6. Thus, an exact match in IFTs for the two processes is difficult to obtain. Overall, the LSS experiments were conducted at slightly higher IFTs (0.12 and 0.025 mN/m) compared to the regular surfactant injection experiments at 0.06 and 0.015 mN/ m. Aging. The cores were aged at 110 °C for 2 weeks. The effective permeabilities to oil at Swi, ko(Swi), were measured before and after aging. In a uniformly wetted core, the effective oil permeability at a given Swi decreases as the wettability is varied from water-wet to oil-wet.31 ko values after aging were reduced to around 50% of the permeability before aging for LS1 and HS1. In LS2 and HS2, however, a lower Swi was obtained. In these cases, ko values after aging were reduced by 80%. Studies have shown that, in an aging process, a decrease in Swi can result in a decrease in water-wetness.4,32
more hydrophobic character for crude BM2. There is a close link between phase behavior and IFT as a function of salinity (see, e.g., the study by Reed and Healy30). This implies that a different surfactant formulation and choice of salinity may be necessary to achieve low IFT while maintaining Winsor I phase behavior for crude BM1 compared to crude BM2. The next step was to perform IFT measurements on systems representative of those to be used in the core flooding experiments. Thus, the total surfactant concentration was lowered from 3 wt % (phase behavior studies) to 0.5 wt %. The results are shown in Table 6. Ideally, one would like to compare the LSS process, with a Winsor I surfactant system, to that of a regular surfactant injection process at the same conditions of phase behavior and IFT. Because of the relationship between salinity, phase behavior, and IFT,30 this investigation must be conducted 6728
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Core LS1 (Brine Salinity of 2550 ppm, i.e. 0.07× SW Composition). Figure 3 shows oil recovery and differential pressure (dP) as a function of injected PVs for core LS1. Initial LS injection resulted in an oil recovery of 56% original oil in place (OOIP), with water breakthrough (WBT) after 0.4 PVs injected. After approximately 3.5 PVs of LS injection, a 0.5 PV LSS slug (σ = 0.12 mN/m) was injected followed by lowsalinity polymer (LSP) injection (10 cP). Injection of polymer increased the pressure from around 100 mbar at Sorw to around 700 mbar at residual oil saturation after chemical injection (Sorc). This is in accordance with the effluent polymer viscosity, which was measured to be 7.5 cP at the end of the flood. Most of the oil from the tertiary flooding process was produced during the polymer injection, resulting in a final recovery of 70% OOIP. Core LS2 (Brine Salinity of 2550 ppm, i.e. 0.07× SW Composition). Figure 4 shows oil recovery and dP as a function of injected PVs for core LS2. LS injection gave a total recovery of 54% OOIP, with a WBT after 0.4 PVs injected. After approximately 3.5 PVs of LS injection, a 0.5 PV LSS slug (σ = 0.025 mN/m) was injected followed by LSP injection (8 cP). During polymer injection, the pressure increased to around 300 mbar at Sorc. This is lower than what would be expected on the basis of the dP at Sorw. However, the reduction in Sor of 17 saturation units during the tertiary process likely affects the dP of the polymer flood. The effluent polymer viscosity was measured to be 7.5 cP at the end of the flood. Most of the oil from the tertiary flooding process was produced during the polymer injection, resulting in a final recovery of 76% OOIP. A higher final recovery compared to core LS1 is consistent with the lower IFT, i.e., higher capillary number, for the tertiary injection process for core LS2. To compare the combined effect of LS and reduced capillarity (LSS injection) to reduced capillarity only, similar experiments were performed using brine compositions in the HS region, i.e., well above 5000 ppm TDS.7 The results of these experiments are discussed in the following. Core HS1 (Brine Salinity of 25 870 ppm, i.e. 0.71× SW Composition). Figure 5 shows the flooding experiment in core HS1. This experiment was not carried out with in situ saturation monitoring. HS brine was initially injected and resulted in a WBT at 0.33 PVs injected and an oil recovery of 51% OOIP. The following 0.5 PV high-salinity surfactant (HSS) slug (σ = 0.06 mN/m) resulted in a pressure drop over the core from around 100 to around 50 mbar. This was not an effect of the change in injection fluid viscosity, because the viscosity of the surfactant solution was measured to be equal to the HS solution. Injection of polymer resulted in a pressure increase from 50 to 500 mbar at the start of the polymer injection, with a decrease toward 400 mbar at the end of the experiment. The HS injection brine in HS1 holds the highest salinity used in this study (Table 6). Surfactant retention is known to increase with increasing salinity.15,24 This is reflected by the oil breakthrough during the tertiary process, which is approximately twice as late here as for the other experiments. Retention mechanisms delay the chemical breakthrough and, thus, delay the oil recovery.33 The total recovery ends on 63% OOIP. Core HS2 (Brine Salinity of 15 300 ppm, i.e. 0.42× SW Composition). In core HS2, a HS secondary flood was followed by a tertiary HSS and polymer flood (Figure 6). Injection of approximately 15 300 ppm diluted SW lead to a recovery of 54% OOIP and a WBT at 0.42 PVs injected. This is an identical
Figure 7. (a−c) In situ oil saturation development during secondary injection in cores (a) LS1, (b) LS2, and (c) HS2, respectively. The graphs are two-dimensional (2D) representations showing oil saturation as a function of the normalized core length at different injection times.
Core Flooding Results. Two cores (LS1 and LS2) were flooded with LS brine (0.07× SW, i.e., 2550 ppm TDS), followed by a LSS slug (0.5 PV) with polymer support. Changes in oil saturations as a function of position and number of PVs injected were monitored by performing continuous Xray scans along the length of the core during the course of the experiment. 6729
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Table 7. Summary of Oil Recoveries, Residual Oil Saturations, Nc, and Relative Permeabilities after Injection Stages LS1 Soi ko(Swi) (before aging) (mD) ko(Swi) (after aging) (mD) Nc (LS/HS) secondary recovery (% OOIP) Sorw Nc (LSSP/HSSP) IFT (mN/m) polymer viscosity (cP) tertiary recovery (% OOIP) Sorc (LSSP/HSSP) ΔS0 Sorc (calculated from scans)
LS2
HS1
Water Flood Recovery, Secondary Recovery 0.69 0.77 0.64 400 500 550 220 100 250 6 × 10−7 5 × 10−7 1 × 10−6 56 54 51 0.30 0.35 0.31 Recovery after Surfactant and Polymer Injection, Tertiary Recovery 6 × 10−4 2 × 10−3 1 × 10−3 0.12 0.025 0.06 10 8 11 69 76 63 0.21 0.18 0.24 0.09 0.17 0.07 0.16 0.16
HS2 0.74 500 100 2 × 10−6 54 0.34 4 × 10−3 0.015 8.5 70 0.22 0.12 0.21
the in situ saturation profiles prior to reaching Sorw are similar, as are the final Sorw values. Tertiary Injection. After initial water flooding with LS or HS brines, the cores were injected with different surfactant formulations, giving rise to a range of IFTs from 0.12 to 0.015 mN/m, followed by a polymer drive. All surfactant formulations gave rise to a lower phase microemulsion system (Winsor I) when equilibrated with the brine and oil phases involved in the experiments. To check for the presence of highly viscous phases, if any, the viscosity of the lower microemulsion phases were measured after phase samples had been equilibrated for 2 weeks. In all cases, the microemulsion viscosity was more or less equal to the brine viscosity. Panels a−c of Figure 8 show the oil saturation as a function of the normalized core length for cores LS1, LS2, and HS2, respectively. The oil appears to be evenly distributed in the core after primary drainage in all experiments, as seen by the gray curves in the oil saturation graphs. Further, no holdup of the oil phase at the core outlet during water flood is observed (see red curves in panels a−c of Figure 8); i.e., there are no indications of a capillary end effect. This is an important observation, because the presence of such a laboratory artifact could contribute to the oil production when the capillarity is reduced during the surfactant flooding step. The average residual saturations after each flood calculated from the scans are in agreement with the material balance values (see Table 7 and Figure 9). In all experiments, the oil saturation at Sorc increases toward the core outlet. The last measuring point (normalized core length = 1) for LS1 and HS2 has Sorc = Sorw (see panels a and c of Figure 8), even though the average change in saturation for the cores is 0.09 and 0.21, respectively. This leads us to conclude that the surfactant slug likely contained an insufficient amount of surfactant to mobilize oil at the core outlet to the same extent as at the core inlet. With continuous surfactant injection, a lower average Sorc similar to Sorc at the core inlet would likely be obtained. Material balance residual oil saturations are average saturations at a given injection time calculated on the basis of produced fluids. The oil recovery in core LS2 is used as an example (Figure 9) to show the average oil saturation calculated from both material balance and X-ray measurements, as a function of PVs injected. There is a good match between the two curves, and the deviation is within the experimental error of the X-ray scanner of 5%. A similar match was also
recovery factor as for LS2, leaving equal oil potential for the tertiary processes in these two cores. A 0.5 PV HSS slug (σ = 0.015 mN/m) was injected after 3 PVs. The first oil was produced toward the end of the surfactant injection. Oil production continued during the first PV of polymer injection, leaving a total oil recovery of 70% OOIP. The effluent polymer viscosity was measured to be 7.5 cP at the end of the flood. Secondary Injection. Panels a−c of Figure 7 show the in situ saturation plots for water flooding in cores LS1, LS2, and HS2, respectively. The capillary number of the core floods was around 1 × 10−6, and the plots show oil saturation as a function of the normalized core length at different stages during the injection process. The average Soi and Sorw values from the in situ saturation plots are in agreement with the material balance values listed in Table 7. The shape and development of saturation fronts can give information about wettability and reveal the presence of capillary end effects. For example, in low-rate floods on strongly wetted cores, the flood front becomes dispersed because the capillary forces become more important relative to the applied viscous flow.34 In these experiments, the secondary saturation profiles are nearly piston-like for all of the cores, with no significant or systematic differences in the shape and development of the profiles between the LS and HS profiles, respectively. Capillary end effects are caused by the sudden discontinuity of capillarity in the wetting phase and tend to maintain an excessive saturation of the wetting phase in the vicinity of the outflow face of the flooded system.34 Capillary end effects commonly appear in situations of oil displacing water in strongly water-wet cores,35 i.e., primary drainage. The Swi and Soi curves in Figures 7 and 8, respectively, are evenly distributed throughout the core, indicating that capillary end effects did not significantly affect the drainage process for these cores. The Sorw curve for HS2 on the other hand (Figure 7c) shows an increase in water saturation by approximately 10 saturation units at the core outlet after water injection. This could indicate a capillary end effect during water flooding in this core. It is somewhat surprising that the behavior of HS2 differs from that of LS1 and LS2 in this aspect, given that there is no significant difference between the available wettability indicators for the cores. Both the decrease in kro(Swi) after aging (see Table 7) and the observed two-phase production after WBT indicate that the wettability in the cores differs from strongly water-wet. Further, 6730
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Figure 9. Comparison of oil saturation as a function of injected PVs based on material balance (blue curve) and X-ray measurements (red curve) for core LS2.
changes and propagates toward the outlet during injection of the surfactant slugs. In core LS1, the IFT between the surfactant slug and the oil is 0.12 mN/m. Despite the observed changes in oil saturation during this process (Figure 10a), the response on the dP is small (Figure 3). The explanation may be that the IFT is not low enough to create a large enough oil bank to cause changes in the dP. The oil saturation near the core inlet was reduced by 5 saturation units during the LSS process. In the next core, LS2, the IFT is reduced by a factor of 5 (σ = 0.025 mN/m) and a more pronounced oil mobilization is observed during the LSS injection stage compared to core LS1 (Figure 10b). The oil mobilization is accompanied by an increase in the dP over the core (Figure 4). Oil mobilization near the core inlet by the LSS process amounts to 24 saturation units. The average oil saturation for the core is reduced from 0.35 at Sorw to 0.11 at the end of the LSS process, Sorc. The green curve in Figure 10b show increased oil saturation at the core outlet at approximately 3.5 PVs injected, which is in accordance with oil breakthrough from the oil recovery material balance in Figure 4. The surfactant slug in the next core, HS2, has the lowest IFT in this study, i.e., 0.015 mN/m. Still, the mobilized oil bank is not large enough to create a pressure increase over the core, as was seen for LS2 (Figure 6). During injection of the HSS slug, the oil saturation near the core inlet decreases by 18 saturation units. From Figure 6 and material balance, the oil breakthrough occurs between 3.4 and 3.6 PVs, which corresponds to the increased oil saturation at the core outlet at 3.55 PVs (green curve in Figure 10c). Because the surfactant slug is expected to contain enough total surfactant to cover the adsorption capacity near the core inlet, even at HS conditions, the effect of lowering the IFT on oil mobilization can be studied by comparing the saturation near the core inlet. Starting with the LSS experiments, reducing the IFT from 0.12 mN/m (LS1; Figure 10a) to 0.025 mN/m (LS2; Figure 10b) reduces the oil saturation by 19 units. However, although IFT is further reduced during the surfactant flooding of core HS2 (σ = 0.015 mN/m), the oil saturation is 6 units higher than in LS2 at the end of the surfactant slug. For each of the cores, polymer was injected immediately after the 0.5 PV surfactant slugs. The polymer viscosity was measured to be around 10 cP at 10 s−1 for the injected polymer solutions. A closer look at the Sorc curve in each experiment reveals that the surfactant slugs are too short if we
Figure 8. (a−c) Oil saturation as a function of the normalized core length at Soi (gray curve), Sorw (red curve), and Sorc (green curve) for cores (a) LS1, (b) LS2, and (c) HS2, respectively.
found for the cores LS1 and HS2. The deviation is largest during the tertiary process of oil mobilization and production. The residual oil after the experiment is 0.16 based on MATLAB calculations and X-ray scans and 0.18 based on material balance. For each of the cores, the surfactant slug was injected after approximately 3 PVs of water injection. Panels a−c of Figure 10 show oil saturation as a function of the normalized core length obtained from the in situ saturation measurements during the 0.5 PV surfactant slug injections for cores LS1, LS2, and HS2, respectively. The yellow curves in panels a−c of Figure 10 are the oil distribution after water flooding at Sorw. As is evident from the figure, the oil saturation distribution inside the cores 6731
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Figure 11. (a−c) In situ oil saturation development during the polymer flood for cores (a) LS1, (b) LS2, and (c) HS2, respectively. The graphs are 2D representations showing oil saturation as a function of the normalized core length at different injection times.
Figure 10. (a−c) In situ oil saturation development during a 0.5 PV surfactant slug injection in cores (a) LS1, (b) LS2, and (c) HS2, respectively. The graphs are 2D representations showing oil saturation as a function of the normalized core length at different injection times.
In cores LS2 and HS2, the oil saturation of the first 0.15 PV of the core length has reached Sorc during the surfactant injection; i.e., the surfactant has effectively mobilized and displaced oil here. From 0.15 PV of the core length and toward the outlet, the polymer sweeps the oil solubilized by the surfactant slug and an oil bank propagates toward the core outlet. If the surfactant slugs had been large enough, the average Sorc would possibly be equal to Sorc reached near the core inlets. For instance, would Sorc in LS2 reach a value of 0.1, instead of the observed 0.18? A Sorc value of 0.1 in LS2 would be in line with previous experiments reported for LSS experiments with continuous surfactant injection with the same reduction in IFT.23
assume that the polymer only works as a pressure drive. The Sorc curves (purple curves in Figure 11) gradually increase from the core inlet to outlet, leaving higher oil saturations at the core ends. The banking of oil in core LS1 (Figure 11a) occurs after 0.2 PV inside the core and after 0.1 PV polymer injected. As oppose to the other experiments, the oil bank appears as a peak, which propagates through the core toward the outlet. The moderate oil recovery by the tertiary process in this core is reflected by the small oil bank developed. The viscoelastic property of the polymer solution reduces the oil saturation at the core inlet further by 3 saturation units. 6732
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saturations between 7 and 17% were obtained by polymersupported surfactant slug injection, depending upon the brine salinity and capillary number. A higher final recovery would likely have been obtained with a larger slug size.
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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 through the PETROMAKS program.
Figure 12. Graph shows Nc as a function of Sorc* between the surfactant solution and the oil for the flooding experiments in this study. Blue squares represent LSS experiments, while red squares represent HSS experiments.
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Table 7 summarizes the four core floods, including Nc calculated using eq 1. ΔS0 is the change in oil recovery after the chemical injection, i.e., Sorc − Sorw. Values of Nc for the tertiary processes, i.e., Nc (LSSP/HSSP) as noted in the table, are calculated using the polymer viscosity and surfactant IFT. In reality, the experimental design is to inject a 0.5 PV surfactant slug, followed by a polymer drive until oil production has ceased. Hence, as discussed in the Introduction, using the polymer viscosity and the surfactant IFT as a single continuous process probably leads to an overestimation of Nc for the process. However, disregarding the polymer viscosity entirely would likely give an underestimation of Nc for the process. The capillary number, Nc, increases in the order LS1 < HS1 < LS2 < HS2, increasing by a factor of roughly 10 from LS1 to HS2. Assuming that we are over the critical capillary number, Ncc, Sor should thus decrease in the reverse order, i.e., with the highest Nc (HS2) giving rise to the lowest Sor, according to typical capillary desaturation behavior.17,36,37 However, as seen from Figure 12, the data from the HS and LS experiments seem to follow two different courses, with the surfactant floodings in a LS environment giving rise to lower residual oil saturations at slightly lower Nc. In Figure 12, Sor* is the normalized residual oil saturation after chemical injection, i.e., Sorc/Sorw. Because there was no significant difference between Sorw after HS and LS flooding, respectively, the mean value of 0.33 based on all four secondary water floods was used when calculating Sorc*.
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CONCLUSION CDC data from the HSS and LSS experiments seem to follow two different curves, with the surfactant flooding experiments in a LS environment giving rise to lower residual oil saturations. This indicates that there is a combined effect of IFT reduction and LS on recovery compared that from a reduction in IFT alone. Even though this combined effect is seen in the tertiary recovery process, no difference in oil recovery or saturation distribution was found between the secondary LS and HS flooding processes for the specific COBR composition used in this study. Although the in situ saturation profiles reveal that the surfactant slug sizes were too small, reductions in residual 6733
NOMENCLATURE AN = acid number APS = alcohol propoxy sulfate CDC = capillary desaturation curve COBR = crude oil/brine/rock HS = high salinity HSS = high-salinity surfactant HSP = high-salinity polymer HSSP = high-salinity surfactant polymer IAA = isoamyl alcohol IFT = interfacial tension I = intensity counted by detector IOS = internal olefin sulfonate kro = relative permeability to oil Kw = absolute permeability to water LS = low salinity LSE = low-salinity effect LSS = low-salinity surfactant LSP = low-salinity polymer LSSP = low-salinity surfactant polymer Nc = capillary number Ncc = critical capillary number OSS = optimal surfactant salinity PO = propylene oxide ppm = parts per million PV = pore volume S* = optimal salinity SBA = secondary butanol SPi = solubilization parameter for phase i SP* = solubilization parameter at optimal salinity Soi = initial oil saturation Sorc = residual oil saturation after chemical injection Sorw = residual oil saturation after water flood Sorc* = normalized residual oil saturation after chemical injection SW = seawater Swi = initial water saturation TDS = total dissolved solids WBT = water breakthrough u = Darcy velocity ϕ = porosity μ = viscosity σ = interfacial tension dx.doi.org/10.1021/ef500995y | Energy Fuels 2014, 28, 6723−6734
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