Investigation of Low-Salinity Waterflooding in Secondary and Tertiary

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Investigation of Low-Salinity Waterflooding in Secondary and Tertiary Enhanced Oil Recovery in Limestone Reservoirs Asghar Gandomkar† and Mohammad Reza Rahimpour*,†,‡ †

Department of Chemical Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz 71345, Iran Department of Chemical Engineering and Materials Science, University of California, Davis, Davis, California 95616, United States

‡

ABSTRACT: Improved oil recovery from oil-wet low-permeability limestone reservoirs is a great challenge by altering the reservoir rock wettability. The purpose of this study is to compare the results of low-salinity waterflooding in secondary and tertiary modes to decrease the residual oil saturation from limestone reservoirs. Three different stock-tank crude oils and limestone cores are used in this study. All of the coreflooding experiments were performed at 60 °C and 2000 psi by injection of actual formation and seawater, with brine solutions containing single-component salt, such as MgSO4, KCl, Na2SO4, CaCl2, MgCl2, and NaCl, with a wide range of salinity levels. During low-salinity flooding in secondary recovery, the dominant displacement-suggested mechanism is snap-off, which results in an oil recovery factor with different values for the various wettability conditions. The most interesting result is that tertiary low-salinity recovery was never observed in these coreflooding experiments. The measured effect of tertiary low-salinity waterflooding from limestone core experiments was rock dissolution, as a result of surface reactions, and an increase in water relative permeability.

1. INTRODUCTION The tertiary oil recovery is mainly dependent upon the properties of oil/aqueous/formation interfaces. These are capillary forces, contact angle, wettability, viscous forces, and interfacial tension (IFT). These properties are represented by a dimensionless group called the capillary number, NC, which is a measure of the mobilization of the occluded oil to enhance the oil recovery.1 Low-salinity waterflooding is applied worldwide to improve oil recovery in secondary and tertiary modes. Evidence of enhancement in waterflood efficiency by injecting low-salinity brine has been observed in the laboratory and in the field on both carbonate and sandstone reservoirs.2−10 Rock mineralogy plays a key role in determining the impact of lowsalinity waterflooding. Because of this, a review of the impact of low-salinity waterflooding on both carbonate and sandstone rocks is presented as follows at laboratory and field scales in secondary and tertiary modes. The effect of low-salinity waterflooding on sandstone has been thoroughly investigated in contrast to carbonate rocks. Clay particles distributed in the sandstone pore structure play an important role in the suggested wettability alteration mechanism explanations, which is not the case in carbonate rocks.11−16 From the lowsalinity waterflooding in sandstone reservoirs, several mechanisms have been suggested, such as IFT reduction and pH increase by McGuire et al.,17 fines migration by Tang and Morrow,18 multicomponent ionic exchange (MIE) by Lager et al.,14 salt-in effects by RezaeiDoust et al.,19 and wettability alteration20 and osmotic pressure by Buckley and Morrow,21 related to salinity contrasts between the formation water (FW) and injection water. Also, low-salinity waterflooding leads to expansion of the electrical double layer (EDL) between the clay and oil interfaces and altered the sandstone wettability toward water-wet conditions. Therefore, it has a positive impact to oil recovery in both laboratory and field scales.22−26 Zhang et al.15 reported increased recovery in the tertiary mode by reducing © XXXX American Chemical Society

reservoir brine salinity 20 times. Two consolidated reservoir sandstone cores were used. X-ray diffraction indicated that each of the cores were rich in chert and kaolinite. Two different crude oils and a mineral oil were used. They conducted waterflood and spontaneous imbibition experiments using four different samples of Berea sandstone and three different crude oils. The impact of low-salinity brine varied significantly between the different samples of Berea, suggesting that mineralogy was the most important variable affecting improved recovery. These authors observed that cores responded to lowsalinity brine in the secondary mode but not the tertiary mode. Lager et al.14 noticed a significant drop in Ca2+ and Mg2+ effluent concentrations during a low-salinity waterflood in the sandstone cores. The high-salinity waterflood achieved a recovery of 48% of original oil in place (OOIP) during secondary mode. Also, in several experiments, they indicated that, if the connate water contains divalent cations (Ca2+), additional oil recovery occurs in the tertiary mode. Pu et al.27 observed low-salinity tertiary recovery from an almost clay-free core for the first time. They observed that injection of 10 pore volumes (PV) of low-salinity brine resulted in additional oil recovery of 9.5% of OOIP in tertiary mode after injection of 10 PV of high-salinity brine in secondary mode from essentially clay-free sandstone. They concluded that dolomite crystals in the sandstone cores play a role in the low-salinity recovery mechanism. Removing the dolomite by acidizing the cores showed no improvement in the tertiary oil recovery or pressure response to the coalbed methane water injection. Agbalaka et al.28 conducted waterflood experiments to study the recovery benefit of using low-salinity brine. Incremental oil was recovered in tertiary mode by switching from 4 to 2 to 1% Received: June 3, 2015 Revised: November 17, 2015

A

DOI: 10.1021/acs.energyfuels.5b01236 Energy Fuels XXXX, XXX, XXX−XXX

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were performed to study the compatibility of injection low-salinity water with FW before coreflooding tests at 60 °C. For testing the compatibility of two waters, samples of the waters were taken, filtered to remove any suspended solids, and added to the tubes in the volumes shown in Table 1. The precipitation was observed over time,

NaCl brine in Berea sandstone cores. For the high-salinity secondary waterfloods, tertiary injection of low-salinity brine was injected after 10 PV throughput of the high-salinity brine. Generally, end-point water relative permeability data do not vary significantly between high- and low-salinity waterfloods, in secondary or tertiary modes. Boussour et al.29 tested 1000 ppm of NaCl and 1000 ppm of NaCl with CaCl2 in tertiary mode and obtained 11 and 10.5% of OOIP, respectively. They showed that the presence of divalent cations is not systematically an optimization parameter of injection brine in sandstone reservoirs. Cissokho et al.30 studied the effect of low-salinity waterflooding on clayey sandstone. They observed additional oil recovery up to 15% of OOIP with kaolinite-free samples. Alotaibi et al.31 showed that the low-salinity water did not work on tertiary recovery mode in sandstone cores. Injection of deionized water (DIW) in tertiary mode showed no impact on oil recovery. This demonstrates the disability of low-salinity water as tertiary mode under these experimental conditions. Nasralla et al.22,32 concluded that low-salinity water did not improve oil recovery in tertiary mode, although it was efficient in secondary mode. Also, they observed that the diluted aquifer did not recover more oil in tertiary low-salinity waterflooding on Berea sandstone at 500 psi and 212 °F. In addition, there has been very little study of low-salinity water injection on limestone minerals in tertiary recovery. Many researchers studied the relationship between oil recovery and wettability alteration during low-salinity and smart water injection on carbonate rock.33−36 The feasibility of low-salinity water injection on carbonate rocks to improve oil recovery using different dilutions of seawater (SW) was investigated by Yousef et al.37 Their coreflooding tests showed incremental oil recovery up to 18% with stepwise dilution of the SW in the tertiary water injection mode. Austad et al.3 showed that tertiary low-salinity oil recovery was quite small and varied between 1 and 5% of OOIP, when flooding first with highsalinity FW, 208 940 ppm and then with 100 times diluted FW or 10 times diluted SW because of the small amount of dissolvable anhydrite [CaSO4(s)] in the core material. Shehata et al.38 investigate the impact of low-salinity waterflooding on tertiary recovery mode for the Indian limestone reservoir. Their results showed that injection of 20 times diluted SW did not reduce residual oil saturation in the tertiary mode after injection of high-salinity SW as a secondary recovery mode. However, 50 times diluted SW improved oil recovery from 1 to 3% in tertiary mode after injection of SW and DIW. Jiang et al.39 indicated that no additional oil recovery was observed by lowsalinity brine in tertiary mode from low-permeability phosphoria formation, even if anhydrite dissolution occurs. Even after considerable research, low-salinity waterflooding remains quite controversial. The mechanisms responsible are poorly understood; the reproducibility of published results is doubted; and the scalability of the technology to the field is questioned. Nonetheless, low-salinity waterflooding is appealing because it could offer considerable recovery benefit, is relatively low-cost, and is relatively simple compared to other chemical enhanced oil recovery (EOR) techniques. This work is ongoing to investigate the effect of low-salinity waterflooding in secondary and tertiary modes in limestone reservoirs.

Table 1. Low-Salinity Compatibility Tests, SW (34 000 and 1000 ppm), FW (1000 ppm), and Brine Solutions Containing a Single Component (1000 ppm) Were Mixed with FW (220 000 ppm) Separately, with Volume Proportions of 10:40, 25:25, and 40:10 sample number

1

2

3

FW (220000 ppm) (cm3) NaCl (1000 ppm) (cm3) FW (220000 ppm) (cm3) Na2SO4 (1000 ppm) (cm3) FW (220000 ppm) (cm3) MgSO4 (1000 ppm) (cm3) FW (220000 ppm) (cm3) MgCl2 (1000 ppm) (cm3) FW (220000 ppm) (cm3) KCl (1000 ppm) (cm3) FW (220000 ppm) (cm3) CaCl2 (1000 ppm) (cm3) FW (220000 ppm) (cm3) SW (34000 ppm) (cm3) FW (220000 ppm) (cm3) SW (1000 ppm) (cm3) FW (220000 ppm) (cm3) FW (1000 ppm) (cm3)

10 40 10 40 10 40 10 40 10 40 10 40 10 40 10 40 10 40

25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25 25

40 10 40 10 40 10 40 10 40 10 40 10 40 10 40 10 40 10

and the tubes were left for 24 h. In some cases, maybe it needs more than 24 h to see kinetics of the entire minerals. Then, the clear water (no precipitate) from the samples was taken by a syringe and sent for ion chromatography and inductively coupled plasma (ICP) analysis.40 2.2. Coreflooding Test. A coreflood apparatus was constructed to conduct high pressure, high temperature (HPHT) coreflooding experiments (Figure 1). The apparatus consisted of two high-pressure liquid chromatography (HPLC) pumps, 1.5 in. internal diameter highpressure core holder, constant-temperature air bath, fluid transfer vessels, backpressure regulator (BPR), overburden pressure pump, differential pressure (DP) transducers to measure pressure drop along the core, and visual separator to collect effluent fluid samples. Outlet of the core holder was connected to the BPR, which was used to adjust pressure of the system. Also, overburden pressure of the system was supplied by the special hand pump. The idea behind core preparation is to restore the core back to its original wettability (which in our case is oil-wet) and saturation state (connate water saturation). Below are the steps followed to prepare the reservoir cores.41,42 (1) First of all, the core samples used in this study were cleaned by washing the limestone cores with toluene followed by acetone. (2) A clean core plug is dried in an oven at 120 °C, and the change in weight before and after drying is observed. (3) The porosity and permeability of core plugs are calculated. The helium porosity is calculated using Boyle’s law, and the absolute permeability is calculated using yjr COREVAL apparatus. (4) The core is placed inside a vessel at room temperature and connected to a vacuum pump for 1 h. After that, formation brine is pumped inside the vessel to saturate the core under a confining pressure of 2000 psi. The saturated method was used to calculate the pore volume. (5) The core is placed inside a core holder, and 5 PV of formation brine is pumped to ensure that the core is now in equilibrium with the brine under an overburden pressure of 500 psi. Then, the permeability of the core to brine is calculated. (6) Dead oil is then injected at a high pressure (∼400−500 psi) from the top to bring the core to the residual water saturation. It usually takes 3−4 PV of oil to displace all of the mobile water. After 12 cores were prepared,

2. MATERIALS AND METHODS 2.1. Compatibility Tests. One of the primary causes of scale formation and injection well plugging is the mixing of two or more waters that are incompatible. In this study, several compatibility tests B


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Figure 1. Schematic of the HPHT coreflooding system consisted of two HPLC pumps, core holder, constant-temperature air bath, fluid transfer vessels, BPR, overburden pressure pump, DP, and visual separator (Shiraz University). it was observed that the Soi was about 70%. This can be attributed to the complex pore structure of the cores being used. (7) The end-point relative permeability to oil (at Sw = Swc) is measured. (8) Then, the core plug is taken out of the core holder, placed in a glass jar containing crude oil, and kept in an oven at 80 °C for at least 1 month to allow for the crude oil, brine, and rock to equilibrate. This process ages the reservoir core, and we presume that it restitutes it back to its original wettability and saturation state. (9) After that, the aged core plug is placed inside a core holder and secondary mode recovery was performed by flooding the cores from initial to residual saturation with 10 PV of low- or high-salinity brines. In the following, tertiary mode recovery was performed by switching to low-salinity injection brine lasting 5 PV. The entire coreflooding experiments were run at a frontal advance rate of 0.5 cm3/min (corresponding to 33−41 PV/day depending upon core properties) and reservoir conditions, 60 °C and 2000 psi. The core holder overburden pressure was maintained at 2800 psi.43,44 During coreflooding tests, we determined the oil and water production rate, differential pressure and samples of the effluent were taken using a fraction collector, and a composition analysis was performed. The scaling criterion of Rapoport and Leas45 has been used to remove the dependence of oil recovery upon the injection rate and core length as a result of the capillary end effect. The use of this scaling criterion helps the capillary pressure gradient in the flow direction to be smaller than the imposed pressure gradient. The scaling criterion is given by LVμ ≥ 1, where L is the core length (cm), μ is the viscosity of the displacing phase (cP), and V is the fluid velocity (cm/min). 2.3. Crude Oil. Three different crude oils were used in these lab experiments. Every oil sample was centrifuged to remove solid particles and water brines. Then, all crude oils were filtered with a Millipore vacuum filter to remove any dispersed particles in the crude oil. Hydrocarbon group type analysis is employed to characterize the crude oils A), B, and C (Table 2). The crude oils used during this research are dead oil, and the American Petroleum Institute (API) gravity, acid number (potentiometric titration method), base number (ASTM D974), and asphaltene fraction (IP 143) were measured. All crude oils are composed of paraffinic and aromatic hydrocarbon molecules containing variable amounts of sulfur, oxygen, and nitrogen, trace amounts of metals, such as nickel, vanadium, iron, and copper, and a fair amount of polar components, i.e., relatively high acid number. Crude oil properties are listed in Tables 2 and 3. 2.4. Brine. Brines used for this study were actual FW and SW, with brine solutions containing single-component salt, such as MgSO4, KCl, Na2SO4, CaCl2, MgCl2, and NaCl. A total of 11 different brines were

Table 2. Compositions of Crude Oils A, B, and C Detected by the GC/MS System hydrocarbon type

crude oil A (mol %)

crude oil B (mol %)

crude oil C (mol %)

n-paraffins isoparaffins naphthenes aromatics saturates C15+ aromatics C15+ unknowns total sum

33.363 28.742 19.309 16.447 1.021 1.118 0.000 100.000

29.722 30.511 21.143 15.206 0.851 2.567 0.000 100.000

27.471 33.054 23.491 12.203 2.733 1.048 0.000 100.000

Table 3. Physical Properties of Crude Oils A, B, and C crude oil property specific gravity (SG) (60 °F) (ASTM D40452) molecular weight (g/mol) (IP-86) acid number (mg/g) (KOH) base number (mg/g) (KOH) asphaltene content (wt %) (IP 143) water content (vol %) (ASTM D4377) basic sediment and water (BS and W) (vol %)

crude oil A crude oil B

crude oil C

0.862

0.823

0.881

120.6 1.65 0.47 9.5 0

113.0 0.74 0.1 0 1.2

122.3 1.13 0.93 2 0

0.1

0

0

used with wide ranges of salinity levels. DIW and salts were mixed in the appropriate proportions to make the low-salinity brines. SW was taken from the southwest of Iran and sent for ion chromatography and ICP analysis. Also, SW is different from place to place. Low-salinity FW and SW were prepared by adding a desired volume of DIW to high-salinity FW and SW. Original FW (220 000 ppm) and SW (34 000 ppm) were diluted by 220 and 34 times down to 1000 ppm, respectively. The properties of all brines, such as ionic strength, initial conductivity, concentration, and pH, are reported in Tables 4 and 5. 2.5. Reservoir Core Plugs. The core plugs used during this study were mostly limestone in composition. Table 6 lists the mineral composition [X-ray diffraction (XRD) data] of the carbonate core plug. The results show that the crushed material is composed of about 74% calcite (CaCO3), 11% dolomite [CaMg(CO3)2], 10% anhydrite C


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were all very similar, implying a homogeneous pore structure and mineralogy. The properties of the core samples used in this study are given in Table 7. All of the experiments were conducted in similar cores, to eliminate the possibility that natural variations between cores were responsible for any contrasts between the high- and low-salinity results.

Table 4. Properties of Studied Brines Containing SingleComponent Salt, Such as MgSO4, KCl, Na2SO4, CaCl2, MgCl2, and NaCl brine

salinity (ppm)

ionic strength

pH

conductivity (mS cm−1)

MgCl2 CaCl2 NaCl KCl MgSO4 Na2SO4

1000 1000 1000 1000 1000 1000

0.0315 0.0270 0.0171 0.0134 0.0332 0.0211

6.9 7.3 7.4 7.7 8.1 5.9

2.56 2.20 2.14 1.98 1.40 1.66

3. RESULTS In this study, we present the result of coreflooding tests and low-salinity water compatibility tests. The target of this work is to investigate the impact of low-salinity waterflooding on oil recovery factor, residual oil saturation, and end-point relative permeability in secondary and tertiary modes. A number of main runs were conducted using reservoir rock samples and three different crude oils at 60 °C and 2000 psi. These runs were conducted after several preliminary runs. Brine solutions containing single-component salt, such as MgSO4 (1000 ppm), KCl (1000 ppm), Na2SO4 (1000 ppm), CaCl2 (1000 ppm), MgCl2 (1000 ppm), NaCl (1000 ppm), 34 times diluted SW (1000 ppm), and 220 times diluted FW (1000 ppm) represent the low-salinity water, while brine solution containing MgCl2 (45 000 ppm), original SW (34 000 ppm), and original FW (220 000 ppm) represent the high-salinity water in this study. The compositions of low- and high-salinity waters are reported in Tables 4 and 5. In this study, several compatibility tests were performed to study the compatibility of low-salinity water injection with FW at 60 °C before coreflooding tests. During low-salinity compatibility tests, SW (34 000 and 1000 ppm), FW (1000 ppm), and brine solutions containing a single component were mixed with FW (220 000 ppm) separately. After that, as shown in Table 8, in this work, a sequence of eight coreflooding tests with crude oil A, two coreflooding tests with crude oil B, and also two coreflooding tests with crude oil C were conducted in limestone cores in secondary and tertiary modes. Each coreflooding test was conducted in a separate core. During these coreflooding tests, low-salinity SW and FW (1000 ppm) were injected on tertiary mode. Initial oil and connate water saturation of all limestone cores are presented in Table 7. Also, most of the experiments were repeated; the original and repeat experiments were similar. During coreflooding tests, we determined the oil and water production rate and differential pressure over time. Also, samples of the effluent fluid were taken using a fraction collector and sent for ion chromatography and ICP analysis to investigate the surface reactions occurring at the limestone rock surface. Also, effluent pH and conductivity histories during secondary and tertiary recovery for all coreflooding experiments were performed.

Table 5. Geochemical Analysis and Physical Properties of Original FW and SW, with Low and High Salinity concentration ions Na+ Mg2+ Ca2+ Cl− HCO3− SO42− K+ Br− total dissolved solids (TDS) (ppm) ionic strength conductivity (mS cm−1) pH

FW

220 times diluted FW

SW

34 times diluted SW

71572 2760 12080 133560 45 8 0 0 220025

325.3 12.5 54 607.1 0.20 0.036 0 0 1000

9951 1574 377 19018 329 2419 290 42 34000

293 46 11 559 9.5 71 9 1.5 1000

4.271 96.2

0.019 4.60

0.690 69.0

0.020 3.07

7.92

7.12

7.55

7.4

Table 6. Mineralogy of Limestone Rock Used in This Study, XRD mineral

concentration (wt %)

limestone dolomite anhydrite clay quartz

74 11 10 3 2

(CaSO4), 3% clay (K,H3O), and 2% quartz (SiO2). Porosity and permeability of the core plugs used during this study vary from 21 to 27% and 2−7 mD, respectively. The core plugs are cylindrical in shape with a diameter of 1.5 in. and length between 6.5 and 8 cm. Measured absolute permeability, porosity, and connate water saturation values

Table 7. Properties of the Limestone Core Samples Used in Coreflooding Experiments limestone core number

length (cm)

diameter (in.)

PV (cm3)

grain density (g/cm3)

helium porosity (%)

permeability (mD)

connate water (%)

L1 L2 L3 L4 L5 L6 L7 L8 L9 L10 L11 L12

6.91 7.14 7.69 7.74 7.60 7.67 7.70 7.44 7.59 7.63 7.81 7.10

1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5

21.1 17.7 21.4 20.6 21.6 18.9 21.6 20.4 19.7 22.1 19.4 18.8

2.81 2.80 2.81 2.83 2.81 2.83 2.82 2.80 2.83 2.80 2.82 2.82

26.93 21.90 24.65 23.48 25.14 21.73 24.78 24.17 22.88 25.53 21.90 23.34

6.60 2.20 5.24 3.80 3.37 3.20 4.00 5.30 4.50 5.00 2.90 5.6

28.9 27.8 29.5 23.0 28.2 27.6 29.3 25.4 26.7 28.1 29.0 25.3

D


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Table 8. Results of the Oil Recovery Factor (RF) and Low-Salinity Brines Used during All Coreflooding Tests in Secondary and Tertiary Modes at 60 °C and 2000 psi Using Crude Oils A, B, and C limestone core number

secondary mode

L1 L2 L3 L4 L5 L6 L7 L8 L9 L10 L11 L12

MgCl2 (1000 ppm) MgSO4 (1000 ppm) Na2SO4 (1000 ppm) NaCl (1000 ppm) CaCl2 (1000 ppm) KCl (1000 ppm) FW (1000 ppm) FW (220000 ppm) SW (1000 ppm) SW (34000 ppm) MgCl2 (1000 ppm) MgCl2 (45000 ppm)

tertiary mode diluted diluted diluted diluted diluted diluted diluted diluted diluted diluted diluted diluted

SW FW SW SW FW SW SW SW FW FW FW FW

crude oil

connate water

secondary RF (% OOIP)

tertiary RF (% OOIP)

total RF (% OOIP)

A A A A A A A A B B C C

FW FW FW FW FW FW FW FW FW FW FW FW

54.60 65.56 60.65 40.30 43.36 40.01 36.00 30.23 50.40 39.53 58.19 45.66

54.60 65.56 60.65 40.30 43.36 40.01 36.00 30.23 50.40 39.53 58.19 45.66

54.60 65.56 60.65 40.30 43.36 40.01 36.00 30.23 50.40 39.53 58.19 45.66

3.1. Low-Salinity Compatibility Tests. As a result of these tests, it was observed that no precipitation occurred when mixing both low-salinity FW (1000 ppm) and brine solution containing NaCl (1000 ppm) with high-salinity FW (220 000 ppm) in all samples. However, when low- and high-salinity SW (1000 and 34 000 ppm) and brine solutions containing singlecomponent salt (1000 ppm), such as MgSO4, KCl, Na2SO4, CaCl2, and MgCl2, were mixed with high-salinity FW (220 000 ppm), precipitation occurred immediately in all samples. The precipitation was clear after 10 min, and sample 2, with the volume proportion 25:25, had the maximum precipitation. The samples were left for 24 h at 60 °C. Then, the clear water (no precipitate) from the three samples was taken by a syringe and sent for ion chromatography and ICP analysis in all tests. Figure 2 shows a picture of the compatibility test for low-

sulfate (Na2SO4) and calcium sulfate (CaSO4), with some sodium bicarbonate (NaHCO3) and calcium chloride (CaCl2). 3.2. Pore Size Distribution. The pore size distribution results obtained from core L12 are shown in Figure 3 to understand the multi-scale pore structure in limestone and its evolution with compaction by mercury injection. Jerauld et al.46 found that the ratio of the pore size to the throat size is the parameter that affects the drainage/imbibition hysteresis behavior because it controls the degree of snap-off. The results show that the surface area per unit pore volume and mean hydraulic radius of this core are 39.75 m2/cm3 and 6.255 μm, respectively. Also, the minimum, middle, and maximum pore sizes are lower than 0.02 μm, between 0.02 and 3 μm, and higher than 3 μm, respectively. 3.3. Coreflooding Tests on Crude Oil A. In this section, eight core floods were performed using crude oil A. During these eight tests, seven low-salinity waterfloodings were performed using brine solutions containing a single component and 220 times diluted FW (1000 ppm) and one coreflooding test were performed using original high-salinity FW (220 000 ppm) on secondary mode. Also, low-salinity SW and FW were examined in tertiary mode for all coreflooding tests (Table 8). 3.3.1. MgCl2 and MgSO4. In this part, the impact of the divalent ion, Mg2+, to improved oil recovery of limestone reservoirs is presented in Figure 4. Core L1 was flooded by 1000 ppm of MgCl2 solution and after 10 PV of MgCl2 injection in secondary mode, and the core was flooded by 5 PV of low-salinity SW (1000 ppm) to test the impact of lowsalinity waterflooding in tertiary mode. The limestone core L1 had porosity and permeability of about 26.93% and 6.6 mD, respectively. MgCl2 injection during secondary oil recovery produced 54% of OOIP and pressure drop stabilized at nearly 43 psi after all of the mobile oil displaced by low-salinity water from the core L1. However, pressure drop can be used to detect the breakthrough of the water at the core outlet. There are dramatic increases of pressure drop (69 psi) at PV of 0.40 for core L1. This sharp increase detects breakthrough and can be attributed to the end effect. A total of 31% of the OOIP is recovered at breakthrough time, after injection of 0.4 PV, and also 23% of the OOIP is produced after breakthrough. The lowsalinity SW (1000 ppm) did not improve oil recovery during tertiary mode, which shows that these experimental conditions are not suitable for enhancing oil recovery in tertiary lowsalinity water injection. The pressure drop decreased to 40 psi during tertiary recovery, as evidence of changing in two-phase

Figure 2. Images of compatibility tests for (left) high-salinity SW (34 000 ppm) mixed with high-salinity FW (220 000 ppm), (middle) low-salinity SW (1000 ppm) mixed with high-salinity FW, and (right) low-salinity NaCl solution (1000 ppm) mixed with high-salinity FW, after 24 h, with volume proportion 25:25 at 60 °C.

salinity SW (1000 ppm) and high-salinity FW (220 000 ppm) after 24 h. The original ion concentration of the mixed waters was calculated by knowing the compositions of brines, which are shown in Tables 4 and 5, and the volume proportions in each sample. Table 9 showed the low-salinity water compatibility results for volume proportion 25:25. It is noticed from these results that the precipitation was mainly sodium E


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Table 9. Low-Salinity Compatibility Results with Volume Proportion 25:25 after 24 h, SW (34 000 and 1000 ppm), with Brine Solutions Containing a Single Component (1000 ppm) Mixed with FW (220 000 ppm) Separately, at 60 °C precipitation of ions (ppm) FW (220000 ppm) mixed with low-salinity waters, volume proportion 25:25 ion

MgCl2

MgSO4

Na2SO4

CaCl2

KCl

SW (1000 ppm)

SW (34000 ppm)

+

10 0 31 0 4 2 0 0

24 0 97 7 14 126 0 0

17 0 85 7 12 276 0 0

16 0 73 4 5 3 0 0

11 0 23 0 6 0 0 0

29 0 126 0 11 841 0 0

19 0 96 0 9 565 0 0

Na Mg2+ Ca2+ Cl− HCO3− SO42− K+ Br−

flooding 10 PV of MgSO4 solution in secondary mode, and 5 PV injection of low-salinity FW did not recover more oil in tertiary mode for limestone core L2 at 2000 psi and 60 °C. During MgSO4 solution injection, the pressure drop varied from 29 (breakthrough time) to 11 and stabilized after all of the mobile oil displaced by low-salinity water from the core L2. In addition, the pressure drop decreased to 11 during tertiary recovery (1000 ppm of FW) and then stabilized. In the presence of Mg2+, by substitution of SO42− instead of Cl−, the oil recovery factor increased from 54 to 65.5% of OOIP for cores L1 and L2, respectively. We can suggest that the lowsalinity water depleted in monovalent ions but enriched in potentially determining divalent ions (SO42−) is suitable for improved oil recovery in limestone reservoirs. As shown in Table 4, it must be mentioned that ionic strength of MgSO4 (0.0332) is higher compared to that of MgCl2 (0.0315). If the ionic strength introduces a dominant effect on the expansion of the double layer, the wettability alteration of the system containing a sulfate ion can be better compared to injection brine depleted in SO42−. In other words, decreasing brine salinity causes the electrical diffuse double layer between rock and oil particles to expand, in turn giving increased electrostatic repulsion, which may cross the threshold binding force between rock and oil, releasing the oil from the rock surface and changing the rock wettability. The radius of sulfate anion in solution is considerably higher than chloride anion. Therefore, the negative charge of the sulfate anion in solution is higher than that of the chloride anion, and it is more probable to alter the wettability by controlling the charge of the limestone surface compared to the chloride anion.47 3.3.2. Na2SO4 and NaCl. Figure 5 shows the impact of Na+, in the presence of divalent ion (SO42−) and monovalent ion (Cl−), on oil recovery during two coreflooding tests on cores L3 and L4. A total of 1000 ppm of Na2SO4 was injected for 10 PV, where oil recovery reached 60% of the OOIP in secondary mode. The pressure drop increased slightly to 24 psi (breakthrough time) before becoming more stable at 15 psi at the end of secondary recovery. The oil recovery was about 27% of OOIP after injection of 0.4 PV (breakthrough time), and 33.65% of the OOIP is recovered after breakthrough. Also, no additional oil recovery was observed during injection of 5 PV of low-salinity SW in tertiary mode. We observed a drop in the pressure from 15 to 10 psi at the start of tertiary recovery, and after that, pressure data showed more stability over time during low-salinity SW injection (Figure 5). Core L4 was flooded by 1000 ppm of NaCl solution for 10 PV as a secondary mode. The low-salinity brine recovered only 26% of the OOIP after injection of 0.4 PV, which is the breakthrough

Figure 3. Pore size distribution results obtained from core L12 by mercury injection, with a multi-scale pore structure.

Figure 4. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L1 and L2 by injection of MgCl2 and MgSO4 solutions (1000 ppm) in secondary mode and low-salinity SW and FW (1000 ppm) in tertiary mode, respectively, with crude oil A, at 60 °C and 2000 psi.

relative permeability. A different coreflooding test was conducted on core L2 by flooding 1000 ppm of MgSO4 solution in secondary mode and after 10 PV of MgSO4 injection, and the core was flooded by low-salinity FW (1000 ppm) to investigate the impact of low-salinity waterflooding in tertiary mode. The oil recovery factor was 65.5% of OOIP by F


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Figure 5. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L3 and L4 by injection of Na2SO4 and NaCl solutions (1000 ppm) in secondary mode, respectively, and low-salinity FW (1000 ppm) in tertiary mode (for both cases), with crude oil A, at 60 °C and 2000 psi.

Figure 6. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L5 and L6 by injection of CaCl2 and KCl solutions (1000 ppm) in secondary mode and low-salinity FW and SW (1000 ppm) in tertiary mode, respectively, with crude oil A, at 60 °C and 2000 psi.

time, and 14.3% of the OOIP was recovered after breakthrough. Therefore, NaCl solution improved oil recovery to 40% of OOIP at the end of secondary mode. A significant pressure drop was observed from 77 to 53 psi after breakthrough time, and it became more stable at the end of secondary recovery. Low-salinity SW showed no additional oil recovery after injection of 5 PV as a tertiary mode. The pressure drop decreased slightly from 53 to 47 psi and then stabilized during low-salinity SW injection (1000 ppm). As shown in Table 4, NaCl has less ionic strength (0.0171) compared to Na2SO4 (0.0211). The Debye length is an inverse function of the total ionic strength; therefore, the Debye length of NaCl is higher than that of Na2SO4. Moreover, the properties of SO42− compared to Cl− show that the ionic radius of SO42− (258 pm) is higher than that of Cl− (181 pm) and the hydrated radius and enthalpy of hydration of Cl− (−364 kJ/mol) are less than those of SO42−. In general, considering all of these characteristics leads to an expansion of the double layer more effectively compared to the cases in which Cl− exists.47 3.3.3. CaCl2 and KCl. Figure 6 shows a comparison of oil recovery factors and pressure drops during injection of lowsalinity brine, containing Ca2+ and K+, into cores L5 and L6. In general, it can be observed that, if the low-salinity brine contains a divalent cation (Ca2+), additional oil recovery occurs in secondary mode. The total oil recovery factor during injection of 10 PV of 1000 ppm of CaCl2 and KCl solutions is 43 and 40% of OOIP, respectively. The oil recovery after breakthrough was also increased when low-salinity brine contains a divalent cation (Ca2+) in comparison to a monovalent ion, K+. The maximum pressure drop occurred after injection of 0.54 PV and after that it was stabilized to 62 psi for both CaCl2 and KCl solutions at the end of secondary recovery. The low-salinity FW and SW (1000 ppm) did not improve oil recovery during tertiary mode for cores L5 and L6, respectively. During tertiary recovery, the pressure drops decreased from 62 to 54 and 59 psi and then stabilized for both low-salinity FW and SW, respectively. The results showed that the divalent cation (Ca2+) improved oil recovery compared to the monovalent cation (K+) in the presence of Cl−. 3.3.4. Low- and High-Salinity FW. The results of low- and high-salinity FW on cores L7 and L8 are provided in Figure 7

Figure 7. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L7 and L8 by injection of low- (1000 ppm) and high- (220 000 ppm) salinity FW in secondary mode, respectively, and low-salinity SW (1000 ppm) in tertiary mode (for both cases), with crude oil A, at 60 °C and 2000 psi.

during secondary recovery. In general, it can be observed that the oil recovery factor increased when the salinity of FW was decreased from 220 000 to 1000 ppm. The low- and highsalinity FW was injected for 10 PV, where oil recoveries reached 36.2 and 30% of OOIP in secondary mode, respectively. It can be observed from the pressure data that the maximum pressure drops (breakthrough time) occurred after injection of 0.38 PV, and these were 82 and 27 psi for lowand high-salinity formation brine, respectively. After breakthrough, the oil recovery factor was also increased for lowsalinity FW in comparison to high-salinity water injection in secondary mode. The pressure drops was stabilized to 38 and 20 psi for low- and high-salinity FW at the end of secondary recovery. A total of 5 PV injection of low-salinity SW did not recover more oil in tertiary mode after injection of low- and high-salinity FW in secondary mode for both limestone cores L7 and L8. During tertiary recovery, the pressure drops at the end of flooding were measured to be about 34 and 14 psi for cores L7 and L8, respectively. Rock wettability depends upon G


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Energy & Fuels stability of the water film between the rock surface and crude oil. The stability of the water film is a function of the EDL repulsion that results from surface charges at the solid/water and water/oil interfaces. 3.4. Coreflooding Tests on Crude Oil B. 3.4.1. Low- and High-Salinity SW. In this section, the effect of low- and highsalinity SW injection on secondary recovery and low-salinity FW on tertiary recovery was investigated. Figure 8 shows a

of 1000 and 45 000 ppm of MgCl2 solutions were injected into cores L11 and L12, respectively, for 10 PV in secondary mode, and after that, the cores were flooded by 5 PV of low-salinity FW (1000 ppm) to test the impact of low-salinity waterflooding in tertiary mode (Figure 9). The oil recovery factors were

Figure 9. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L11 and L12 by injection of low- (1000 ppm) and high- (45 000 ppm) salinity MgCl2 solutions in secondary mode, respectively, and low-salinity FW (1000 ppm) in tertiary mode (for both cases), with crude oil C, at 60 °C and 2000 psi.

Figure 8. Results of the oil recovery factor (primary vertical axis) and pressure drop (secondary vertical axis) for limestone cores L9 and L10 by injection of low- (1000 ppm) and high- (220 000 ppm) salinity SW in secondary mode, respectively, and low-salinity FW (1000 ppm) in tertiary mode (for both cases), with crude oil B, at 60 °C and 2000 psi.

significantly increased by injecting 1000 ppm of MgCl2 solution compared to 45 000 ppm MgCl2 solution, and these varied from 58.2 to 45.6% of OOIP, respectively. We noticed a drop in the pressures from 33 to 24 psi and from 68 to 25 psi during the secondary recovery for cores L11 and L12, respectively. After that, pressure data showed more stability over time. The low-salinity FW (1000 ppm) did not improve oil recovery during tertiary mode. During tertiary recovery, the pressure drops decreased from 24 to 16 psi and from 25 to 16 psi and then stabilized for cores L11 and L12, respectively. 3.6. Surface Reactions at the Limestone Rock Surface. The end-point relative permeability to oil and water before and after aging is shown in Figures 10 and 11. Generally, the rock wettability shifts toward the oil-wet state during aging in all limestone cores. As shown in these figures, the end-point oil

small increase in oil recovery when salinity of SW was decreased from 34 000 to 1000 ppm. At the end of injection of 10 PV, the total oil recovery factors were about 39.5 and 50.4% of OOIP during high and low SW injection in secondary mode, respectively. A sharp increase in pressure data was observed up to 73 and 54 psi for both cases of low- and high-salinity SW at breakthrough time, respectively. The pressure drops for the cases of low- and high-salinity SW injection were nearly 48 and 32 psi at the end of secondary recovery, while the core L9 had higher permeability (about 5 mD) compared to the core L10 (about 4.5 mD). Also, it is to be noted that no additional oil recovery was observed during injection of 5 PV of low-salinity FW (1000 ppm) in both cores L9 and L10 in tertiary mode. For the low-salinity FW injection in tertiary recovery, the pressure drops at the end of flooding were measured to be about 45 and 27 psi for cores L9 and L10, respectively. Cationic surfactants of the type alkyl trimethylammonium, RN(CH3)3+, dissolved in SW are able to improve water wetness in limestone reservoirs. 3.5. Coreflooding Tests on Crude Oil C. 3.5.1. Low- and High-Salinity MgCl2. In the previous work,48 low-salinity MgCl2 solution altered the limestone rock wettability toward the strongly water-wet condition (θ = 43°) during contact angle (CA) measurement tests and we expected an increasing in oil trapping by snap-off during coreflooding tests. The results of low-salinity MgCl2 solution with crude oil A were presented in section 3.3 (Figure 4). From these results, in core L1, MgCl2 solution recovered only 54% of the OOIP, which is lower than that compared to intermediate water-wet conditions (MgSO4 solution with θ = 87°). Because of the decrease in the oil recovery factor by snap-off, the MgCl2 solution experiment was repeated using crude oil C and the results were similar. A total

Figure 10. End-point relative permeability to oil, Kro (before and after aging), and water, Krw (at the end of secondary and tertiary recovery), for all coreflooding experiments, performed wih crude oil A, at 60 °C and 2000 psi. H


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such that pressure drops decreased and stabilized during tertiary recovery in all coreflooding tests. All effluent pH and conductivity histories were measured during secondary and tertiary recovery (Table 10). The pH results show that the effluent pH value increased in comparison to injected pH after injection of low- and high-salinity brine during secondary and tertiary recovery. The change of effluent pH and brine salinity simultaneously demonstrates that the pH value is controlled by brine−limestone rock reactions. Conductivity of the effluent brine is a little more than initial conductivity. This is supposed to be owing to dissolution of various limestone minerals and surface reactions occurring at the limestone rock surface. Effluent brine from the cores L2, L4, L7, L9, and L11 was investigated to evaluate the concentration of Mg2+, Ca2+, Na+, and SO42−. Ion concentrations are reported in Table 11 during secondary and tertiary recovery. The Na+ effluent concentration was constant during secondary and tertiary modes from the cores L2, L4, L7, L9, and L11. For example, it was about 184 and 174 ppm after injection of 5 and 10 PV of MgSO4 during secondary mode and 157 ppm after injection of 5 PV of lowsalinity FW during tertiary recovery, respectively, for core L2. The interaction between limestone minerals and low-salinity water might have occurred during the tertiary recovery. Injection of low-salinity water resulted in the release of the calcium cation (Ca2+) from the limestone minerals, which was increasing in tertiary mode. Most likely, the considerable source of a high Ca2+ concentration in effluent brine was calcite (CaCO3) and desorption effects, because the cores used in this study contained 74% calcite. High concentrations of calcium ions in effluent brine might be owing to dissolution of calcite, which could be the conquering factor for increasing in absolute permeability during tertiary recovery. The Mg2+ effluent concentration showed a little change during low-salinity water injection in secondary and tertiary modes. It was about 534 and 561 ppm after injection of 5 and 10 PV of MgCl2 during secondary mode and 589 ppm after injection of 5 PV of lowsalinity FW during tertiary recovery, respectively, for core L11. The SO42− effluent concentration was decreasing, while they reached zero during secondary and tertiary recovery. Carbonate rocks may also contain anhydrite. Frequently, these anhydrites are encapsulated in the rock matrix and are not seriously affected by invading fluids.

Figure 11. End-point relative permeability to oil, Kro (before and after aging), and water, Krw (at the end of secondary and tertiary recovery), for all coreflooding experiments, performed wih crude oils B and C, at 60 °C and 2000 psi.

relative permeabilities decrease as the wettability is altered to oil-wet. During low-salinity waterflooding in secondary mode, EOR was generally accompanied by an increase in waterwetness based on an observed decrease in end-point water relative permeability. During the low-salinity water injection on core L3, the end-point oil relative permeability before and after aging is 0.65 and 0.24, respectively. After that, 1000 ppm of Na2SO4 was injected for 10 PV and the end-point water relative permeability is 0.14 at the end of secondary flooding. These conditions were repeated for other coreflooding experiments during secondary mode. For the low-salinity FW injection in tertiary recovery, the pressure drops at the end of flooding were decreased and stabilized. One interesting result is a slight increase in end-point water relative permeability, during tertiary recovery in all limestone cores (Figures 10 and 11). For example, during the coreflooding test for core L1, the end-point water relative permeability after injection of 10 PV was measured about 0.12, and after that, at the end of tertiary mode, was increased to 0.13. Nonetheless, on the basis of the increasing end-point water relative permeability and stabilizing residual oil saturation, we considered the impact of dissolution of various limestone minerals and surface reactions occurring at the limestone rock surface. The total leaching of divalent cations from the limestone surface (by desorption effects and rock dissolution) causes a change of the absolute permeability,

Table 10. Effluent pH and Conductivity History during Secondary and Tertiary Recovery for All Coreflooding Experiments effluent conductivity (mS cm−1)

effluent pH (incremental pH) limestone core number

secondary recovery after 5 PV (produced pH)

secondary recovery after 10 PV (produced pH)

tertiary recovery after 5 PV (produced pH)

secondary recovery after 5 PV


tertiary recovery after 5 PV

L1 L2 L3 L4 L5 L6 L7 L8 L9 L10 L11 L12

9.70 8.40 9.55 7.50 7.34 7.80 7.18 7.97 7.44 7.62 9.66 9.75

9.73 8.56 9.67 7.54 7.60 7.84 7.30 8.00 7.52 7.67 9.71 9.80

9.86 8.60 9.70 8.00 7.72 8.30 7.36 8.10 7.60 7.84 9.78 9.84

2.59 1.68 1.76 2.43 2.31 2.24 4.49 98.6 3.87 70.2 3.10 56.2

2.65 1.50 1.72 2.39 2.30 2.20 4.58 97.4 3.74 70.1 3.00 56.1

2.89 3.56 2.63 2.67 3.93 3.56 5.65 99.3 4.36 73.5 4.70 58.5

I


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Table 11. Surface Reactions Occurring at the Limestone Rock Surface by Analysis of the Effluent Concentration during Secondary and Tertiary Recovery for Coreflooding Experiments effluent concentration (ppm) secondary recovery after 5 PV


tertiary recovery after 5 PV

limestone core number

Na+

Ca2+

Mg2+

SO42−

Na+

Ca2+

Mg2+

SO42−

Na+

Ca2+

Mg2+

SO42−

L2 L4 L7 L9 L11

184 580 594 632 271

227 104 95 56 153

570 67 47 58 534

595 2 0 22 0

174 567 567 594 147

247 115 112 74 160

561 84 79 43 561

589 0 0 16 0

157 514 544 532 68

286 247 147 158 306

507 23 163 74 589

573 0 0 0 0

4. DISCUSSION 4.1. Low-Salinity Water Injection in Secondary and Tertiary Modes. This research effort was undertaken to study the effect of low-salinity waterflooding on oil recovery in secondary and tertiary mode. This would involve much lower capital investment and operating costs, leading to favorable economics compared to other EOR methods. From the results of FW injection in secondary mode (cores L7 and L8), oil production stopped after 1 PV water injection. Therefore, we can propose that wettability alteration (toward the water-wet) has completely occurred at the end of the aforementioned condition. In contrast, it seems that wettability is not altered from 2 to 10 PV water injections during secondary mode. In this condition, a decrease in pressure drop, despite producing no oil, can be due to the (1) lack of wettability alteration, (2) rock dissolution, and subsequent (3) increase of absolute permeability. Also, we injected FW during cores L2, L5, L9, L10, L11, and L12 during tertiary mode with different water compositions in comparison to water used in secondary mode. It is expected that the wettability alteration shifted toward a more water-wet condition. A higher driving force is required to compensate for this shift. However, this did not happen, which can be explained by another round of rock dissolution and, hence, increase of absolute permeability. The case of the decrease in pressure drop, despite producing no oil, occurs in all core flooding tests with different weights during secondary mode. The maximum pressure drops were observed during core flooding tests, such as cores L1 (MgCl2 flooding), L4 (NaCl flooding), L5 (CaCl2 flooding), L7 (low-salinity FW flooding), L9 (low-salinity SW flooding), and L11 (low-salinity MgCl2 flooding) at the aforementioned condition. The rock dissolution is different from test to test. Also, from Table 11, which showed the surface reactions occurring in the limestone rock during secondary recovery, we can observe that the different effluent concentrations caused several pressure drops. Also, the experimental results and fluid and rock characterization showed tertiary lowsalinity waterflooding after low- and high-salinity waterflooding is not an effective method to enhanced oil recovery for the lowpermeability limestone reservoir, which shows that the doublelayer expansion may not support producing more oil in tertiary recovery as a result of the lack of a continuous oil film. In addition, the efficiency of low-salinity water is a function of the brine ionic strength, rock mineralogy, crude oil, natural wetting condition of the reservoir rock, and how much the reservoir rock wettability is altered as a result of the expansion of the double layer. Low-salinity waterflooding can have a low potential for increasing oil recovery if the original state of the reservoir rock wettability is strongly water-wet. Therefore, wettability alteration of the limestone rock may not be effective

in recovering more oil during tertiary mode. The similar behavior of low-salinity water injection during tertiary mode has been observed by other research groups.38,39 Most of the time, it is observed that the change in the oil recovery factor is higher in secondary mode compared to that in tertiary mode. The composition of the injected brine can alter wetting properties of the reservoir rock during low-salinity waterflooding in a suitable way to improve oil recovery. Therefore, smart waterflooding with an optimum composition and salinity can act as a tertiary recovery method. From Table 8, the maximum oil recovery factor was 65.56% of OOIP by flooding MgSO4 solution, for limestone core L2 saturated with crude oil A, at 2000 psi and 60 °C, during all coreflooding tests. Also, two different coreflooding tests were conducted using crude oils A and C, and low-salinity brine solution containing MgCl2 (1000 ppm) was injected on secondary mode in the same conditions. The results showed that oil recovery factors were 54.6 and 58.19% of OOIP for cores L1 and L11, respectively. Therefore, reservoir crude oil composition has a considerable impact on the efficiency of low-salinity waterflooding and, hence, the improved oil recovery. Figure 12 shows the relationship between the Amott wettability index (from the previous work48) and total oil recovery for SW, FW, and singlecomponent brine solutions, such as MgSO4, KCl, Na2SO4, CaCl2, MgCl2, and NaCl, in secondary mode. These results showed that, as wettability alters from oil-wet to neutral-wet, the oil recovery increases to a maximum for the cases

Figure 12. Relationship between the Amott wettability index and oil recovery factor during single-component brine solutions (1000 ppm), such as MgSO4 (RF = 65.56%), KCl (RF = 40.1%), Na2SO4 (RF = 60.65%), CaCl2 (RF = 43.36%), MgCl2 (RF = 54.06%), NaCl (RF = 40.3%), and SW (1000 ppm, RF = 50.4%; 5000 ppm, RF = 60%; and 34 000 ppm, RF = 39.53%) and FW (1000 ppm, RF = 36%; 220 000 ppm, RF = 30.23%; modified FW at 1000 ppm, RF = 41%; and modified FW at 1000 ppm, RF = 32%). J


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investigated. The oil recovery then decreases with an increase in water-wetness for the injection of brine solutions. Snap-off is the more significant contributor to oil recovery. Where the wetting layers swell ahead of the displacement front composed of fully water-saturated elements, snap-off may occur in the narrower throats, trapping oil in larger elements during strongly water-wet conditions. The improved oil recovery as a result of injection of low-salinity brine in secondary mode can be described by the Derjaguin−Landau−Verwey−Overbeek (DLVO) theory.49 There are two main forces acting in any colloidal system: electrostatic repulsion forces and van der Waals attractive forces. As salinity of the electrolyte decreases, the thickness of EDL and, hence, electrostatic repulsive forces increase, and this ultimately improved microscopic sweep efficiency.

Greek Letters

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REFERENCES

(1) Alotaibi, M. B.; Nasr-El-Din, H. A. Effect of brine salinity on reservoir fluids interfacial tension. Proceedings of the SPE EUROPEC/ EAGE Annual Conference and Exhibition; Amsterdam, Netherlands, June 8−11, 2009; SPE-121569-MS, DOI: 10.2118/121569-MS. (2) Al-Shalabi, E. W.; Luo, H.; Delshad, M.; Sepehrnoori, K. Singlewell chemical tracer modeling of low salinity water injection in carbonates. Proceedings of the SPE Western Regional Meeting; Garden Grove, CA, April 27−30, 2015; SPE-173994-MS, DOI: 10.2118/ 173994-MS. (3) Austad, T.; Shariatpanahi, S. F.; Strand, S.; Black, C. J. J.; Webb, K. J. Conditions for a low-salinity enhanced oil recovery (EOR) effect in carbonate oil reservoirs. Energy Fuels 2012, 26, 569−575. (4) Aladasani, A.; Bai, B.; Wu, Y. S.; Salehi, S. Studying low-salinity waterflooding recovery effects in sandstone reservoirs. J. Pet. Sci. Eng. 2014, 120, 39−51. (5) Robertson, E. P. Oil Recovery Increases by Low-Salinity Flooding: Minnelusa and Green River Formations. Proceedings of the SPE Annual Technical Conference and Exhibition; Florence, Italy, Sept 19−22, 2010; SPE-132154-MS, DOI: 10.2118/132154-MS. (6) Brady, P. V.; Morrow, N. R.; Fogden, A.; Deniz, V.; Loahardjo, N.; Winoto. Electrostatics and the Low Salinity Effect in Sandstone Reservoirs. Energy Fuels 2015, 29 (2), 666−677. (7) Myint, P. C.; Firoozabadi, A. Thin liquid films in improved oil recovery from low-salinity brine. Curr. Opin. Colloid Interface Sci. 2015, 20, 105−114. (8) Hadia, N. J.; Ashraf, A.; Tweheyo, M. T.; Torsæter, O. Laboratory investigation on effects of initial wettabilities on performance of low salinity waterflooding. J. Pet. Sci. Eng. 2013, 105, 18−25. (9) Vledder, P.; Fonseca, J. C.; Wells, T.; Gonzalez, I.; Ligthelm, D. Low salinity waterflooding: Proof of wettability alteration on a field wide scale. Proceedings of the SPE Improved Oil Recovery Symposium; Tulsa, OK, April 24−28, 2010; SPE-129564-MS, DOI: 10.2118/ 129564-MS. (10) Romero, M. I.; Gamage, P.; Jiang, H.; Chopping, C.; Thyne, G. Study of low-salinity waterflooding for single- and two-phase experiments in Berea sandstone cores. J. Pet. Sci. Eng. 2013, 110, 149−154. (11) Austad, T.; RezaeiDoust, R.; Puntervold, T. Chemical mechanism of low salinity waterflooding in sandstone reservoirs. Proceedings of the SPE Improved Oil Recovery Symposium; Tulsa, OK, April 24−28, 2010; SPE-129767-MS, DOI: 10.2118/129767-MS. (12) Zhang, P.; Tweheyo, M. T.; Austad, T. Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42−. Colloids Surf., A 2007, 301, 199−208. (13) Mahani, H.; Berg, S.; Ilic, D.; Bartels, W. B.; Niasar, V. J. Kinetics of low-salinity-flooding effect. SPE J. 2015, DOI: 10.2118/ 165255-PA. (14) Lager, A.; Webb, K. J.; Black, C. J.; Singleton, M.; Sorbie, K. S. Low salinity oil recoveryAn experimental investigation. Proceedings of the International Symposium of the Society of Core Analysts; Trondheim, Norway, Sept 12−16, 2006. (15) Zhang, Y.; Morrow, N. R. Comparison of secondary and tertiary recovery with change in injection brine composition for crude oil/ sandstone combinations. Proceedings of the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, OK, April 22−26, 2006; SPE-99757-MS, DOI: 10.2118/99757-MS. (16) Attar, A.; Muggeridge, A. Impact of geological heterogeneity on performance of secondary and tertiary low salinity water injection. Proceedings of the SPE Middle East Oil & Gas Show and Conference;

5. CONCLUSION (1) The dominant displacement-suggested mechanism is snapoff, which results in the oil recovery factor with different values for the various wettability conditions during low-salinity flooding in secondary recovery. (2) The precipitation was mainly sodium sulfate (Na2SO4) and calcium sulfate (CaSO4), with some sodium bicarbonate (NaHCO3) and calcium chloride (CaCl2), during low-salinity compatibility tests. (3) The oil recovery factor confirmed that SW will act as an EOR fluid in limestone reservoirs compared to low-salinity FW during secondary mode at certain conditions. (4) It appears that the limestone reservoir may not be compatible to lowsalinity waterflooding in tertiary mode. It needs more investigations by smart waterflooding. (5) Leaching of calcium cation (Ca2+) from the limestone surface is most likely to be the main reason for the increase in absolute permeability in tertiary mode.

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θ = contact angle

AUTHOR INFORMATION

Corresponding Author

*Telephone: +98-713-2303071. Fax: +98-713-6287294. E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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NOMENCLATURE OOIP = original oil in place HPHT = high pressure, high temperature HPLC = high-pressure liquid chromatography BPR = backpressure regulator DP = differential pressure MIE = multicomponent ionic exchange XRD = X-ray diffraction EDL = electrical double layer FW = formation water (ppm) SW = seawater (ppm) DIW = deionized water CA = contact angle (deg) IFT = interfacial tension (mN/m) EOR = enhanced oil recovery TDS = total dissolved solids (ppm) SG = specific gravity ICP = inductively coupled plasma DLVO = Derjaguin−Landau−Verwey−Overbeek Soi = initial oil saturation Sw = water saturation K


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Investigation of Low-Salinity Waterflooding in Secondary and Tertiary

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