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Influence of Individual Ions on Oil/Brine/Rock Interfacial Interactions and Oil Water Flow Behaviors in Porous Media Bing Wei, Runnan Wu, Laiming Lu, Xuewen Ning, Xingguang Xu, Colin D. Wood, and Yang Yang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02458 • Publication Date (Web): 24 Oct 2017 Downloaded from http://pubs.acs.org on October 27, 2017

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Influence of Individual Ions on Oil/Brine/Rock Interfacial Interactions and Oil Water Flow Behaviors in Porous Media Bing Wei,1,* Runnan Wu,1 Laiming Lu,1 Xuewen Ning,1 Xingguang Xu2, Colin Wood2, Yang Yang1,2 1)

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum

University, Chengdu, Sichuan 610500, China 2)

Energy Business Unit, The Commonwealth Scientific and Industrial Research Organization, 26 Dick

Perry Avenue, Kensington 6152, Perth, Australia

ABSTRACT The low salinity effect (LSE) in enhanced oil recovery (EOR) is widely accepted. However, its underlying mechanisms remain unclear due in part to the complex interactions at oil/brine/rock interface. Since the chemistry of brine largely depends on the ionic composition. Thus, in this work, attention was placed on the roles of individual ion and salinity in LSE through direct measurements of oil/brine/rock interfacial behaviors, oil displacement efficiencies and oil water relative permeability in sandstone porous media. The results showed that the oil/water IFTs were weakly dependent on ion and the lowest IFTs were generated at the salinities of 0.2-0.5 wt%. In contrast, the interfacial dilational modulus varied significantly with ion types and salinities due to the adsorption of polar components at the oil/water interface. Moreover, wettability alteration of the sandstone surface was found to be associated with the divalent ions in our work. As a result of the viscoelastic interfaces, the breakage of oil column into oil droplet or ganglia was delayed, which subsequently led to the improvement of the oil water relative permeability and oil displacement efficiencies. Based on the analysis, it was concluded that HCO3-, Mg2+ and SO42- were potential-determining-ions (PDIs) in LSE. The results of the tests, to our knowledge, are the first that particularly emphasizes the roles of individual ion at the interfaces and oil water flow patterns in porous media. 1. INTRODUCTION In the past few decades, extensive research on the low salinity effect (LSE) has been conducted by worldwide research institutes and oil companies.1-5 The results of 1

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laboratory studies and field tests in both sandstone and carbonate lithologies have confirmed the LSE.6-9 In practice, to achieve the LSE, the brine chemistry or ionic strength can be engineered by either diluting the high salinity (HS) brine or tuning the content of individual ion. Despite the intensive studies of the LSE, its underlying mechanisms remain poorly understood due in part to the complexity of the oil, brine and rock mineral compositions and also the induced multi-interactions at the interfaces. Another fact complicating the LSE is that the reported data supporting a specific mechanism are usually inconsistent with or even contradict the observations of other literature.4, 8, 10-13 To date, more than seventeen hypotheses have been proposed to explain the LSE.14-17 Of the possible mechanisms, clay swelling and fines migration,18-20 multi-ion exchange (MIE),3,

4, 10, 21-24

local increase in pH,12,

25, 26

double layer expansion

(DLE),4, 7, 27-29 and interfacial viscoelasticity30, 31 are among the leading candidates. The above mechanisms result in the effects of rock wettability alteration, IFT reduction, thief zone obstacle, snap-off hindrance, etc., which ultimately lead to a higher oil recovery efficiency compared to re-injection of produced brine. It was reported that the incremental oil recovery could be increased up to 35% in bench scale experiments, whereas in field tests, 50% of the residual oil saturation was reduced due to LSE.8, 32, 33 However, as mentioned, some other published and unpublished works didn't observe the LSE benefits.34-36 Since the chemistry of the brine is closely related to its ionic composition, for a given oil-rock system, to understand the mechanisms behind and design the optimum recipes, the research focus should be given to the role of individual ion in LSE. Alotaibi and Yousef presented an eletrokinetic study of the divalent and monovalent ions in carbonate.37 They found that the electrical properties of the calcite surface and oil/water interfaces varied significantly with ion types, thus leading to different performances of Na+, Mg2+, Ca2+ and SO42- in emulsification and wettability alteration. Garcia-Olvera and Alvarado compared the interfacial properties of sulfate-enriched low salinity (LS) and HS brines. It was claimed that the sulfate containing brine modified the fluid-fluid interactions by changing the interfacial viscoelaticity, and 2


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subsequently depressed the "snap-off" of the oil phase.38 The effects of Ca2+ and SO42as PDIs on the chalk surfaces were examined using zeta potential and spontaneous imbibition tests.39 The results showed that the presence of these two ions facilitated EOR at the core scale. Although the role of individual ion at the interfaces involved in LSE has been generally recognized, there is still no way to determine the optimum composition for a specific reservoir based on the currently available results. In our previous work, the effect of salinity on oil/water IFTs, rock affinity, surface zeta potential, macro/micro oil recovery efficiencies, etc., at a certain ion ratio, were comprehensively studied.4 Herein, this paper mainly focuses on the influences of ion type and salinity on LSE. Our primary interest was to understand the play of individual ion at the oil/brine/rock interfaces and oil water flow behaviors in porous media. To accomplish this research objective, the prevalent cations and anions including Ca2+, Mg2+, Na+, HCO3-, Cl- and SO42- were extracted from the formation brine. After that, the direct measurements of the interfacial interactions using IFT, interfacial dilational modulus and contact angle were conducted. In addition, the emulsifying behaviors of different ions were also visually investigated. The oil and water flow patterns in porous media were represented by the relative permeability curves, and then related to the results of oil displacement tests and interfacial behaviors. The main differences between this study and other published works are, 1. The available literature of LSE mainly focused on the static properties, but in this study, particular emphasis was placed on oil water dynamic flow behaviors in porous media; 2. The relationship between dynamic flow behaviors and static observations was established; 3. The PDIs of LSE were re-defined on the basis of the collected data. It is believed that these results can add new insights to LSE and help to design the optimum ionic composition for low salinity waterflooding (LSWF) process. 2. EXPERIMENTAL SECTION 2.1 Materials The crude oil used in this work was kindly provided by Xinjiang Oilfield Co. Table 1 lists the basic properties of this oil. The compositional analysis of the oil is shown in Fig. 1. Five stock synthetic brines with a salinity of 10 wt% were prepared using the 3


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prevalent ions in formation brine and then diluted to make a series of low salinity brines. The inorganic salts of NaCl (99.99%), NaHCO3 (≥99.8%), MgSO4 (≥99%), K2SO4 (99%) and CaCl2 (≥99.9%) were supplied by Kelong Chemicals Inc., Chengdu, and used as received. The properties of the tested brines including salt solubility were tabulated in Table S1. Table 1 Basic properties of the crude oil Viscosity@25oC

Density@25oC

(mPas)

(gmL-1)

138

SARA (wt%)

0.796

Saturate

Aromatic

Resin

43.55

36.63

9.78

n-heptane insoluble asphaltene 4.15

Note: SARA represents the fractions of crude oil, saturate, aromatic, resin and asphaltene, respectively. 7

Weight percentage (%)

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6 5 4 3 2 1 0 C6

C8

C10

C12

C14

C16

C18

C20

C22

C24

C26

C28

C30

C32

C34

>C35

Carbon number

Figure 1. Carbon number distribution of the crude oil 2.2 IFT measurements The IFTs between the crude oil and brine were measured by the spinning drop method using a Bowing TX-500C spinning drop tensiometer (Stafford, TX). The IFTs were read automatically by an image capture device equipped with image acquisition software. All the tests were carried out at 25°C. 2.3 Interfacial dilational rheology The dilational rheology of the oil water interfaces were measured using a spinning drop tensiometer (SVT20N, Dataphysics, Germany) by sinusoidally oscillating the oil drop volume (5µL). The responses of the drop volume as a function of frequency (0.02, 0.05 and 0.08Hz) were captured and recorded by a CCD camera and then 4


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digitized for analysis.40,

41

After fitting, the dilational moduli of the oil water

interfaces were output from the data acquisition system. All the measurements were performed at a constant temperature of 25°C. The interfacial dilational modulus (E) is defined as the variation of interfacial tension (γ) with relative interfacial area (A) as follows: ୢγ

‫ = ܧ‬ୢ୪୬୅

(1)

This modulus has contributions from both elastic (E') and viscous (E'') components which can be expressed as, ‫ ܧ = ܧ‬ᇱ + ݅‫ܧ‬′′

(2)

and ‫ ܧ‬ᇱ = ‫(ܧ‬sinθ) ‫ ܧ‬ᇱᇱ = ‫(ܧ‬cosߠ) ‫ܧ‬′′ ‫ܧ‬′ The phase angle, θ, is the phase difference between the interfacial tension and surface tanߠ =

area oscillations. 2.4 Contact angle measurement Polished sandstone rock slides were first cleaned with alcohol and distilled water, and then placed to a 60 °C oven for drying. The oil-wet surfaces were created by aging the slides in the crude oil (60 °C) for one week. The ion-induced alterations of surface wettability were examined through exposing the slides in brines that have different ionic compositions. The contact angle of an oil drop formed on the surface was re-measured as a function of the exposure time using a Kruss 25 drop shape analyzer in the aqueous phase of the same brine. The contact angle measures and slide soaking were conducted at 25 oC. 2.5 Emulsion preparation The emulsifying tests were conducted using 50 mL reagent bottles. Five brines with the same salinity (0.2 wt%) were first added to the bottles. Then, the crude oil was dropped gently to the top of the aqueous phase using a syringe in the oil water volume ratios varying from 1:9 to 5:5 to test the phase behavior upon ionic composition and 5


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oil content. Two phases were subsequently mixed through hand-shaking the bottles for 1min.42 The phase behaviors of the mixtures were recorded upon static storage. 2.6 Oil displacement tests Figure 2 shows the simplified setup of the oil displacement tests. The porous media using in this section was unconsolidated models, which were packed with homogeneous 300 mesh glass beads. Table 2 outlines the parameters of the 15 tests. To respect the initial reservoir conditions, the model was first saturated with HS brine (2 wt%) to determine the pore volume (PV) and permeability to water (K). Then, the crude oil was injected into the model to displace the brine and create the initial oil saturation (Soi) and connate water. The injection of different salinity brines was subsequently conducted to mimic secondary waterflooding in oilfields until the water cut reached 98%. The oil displacements were conducted under ambient pressure and temperature. A constant flow rate of 0.4 mL/min was used throughout this part of work.

Figure 2. Simplified schematics of the oil displacement test setup 2.7 Unsteady-state coreflooding tests Using the experimental setup described above for oil displacement tests, the unsteady-state coreflooding tests were conducted in order to establish the relative permeability curves of oil and water phases according to the standard method of SY/T 5345-2007. The operating conditions were similar with those of the oil displacement tests (ambient pressure and temperature, flow rate of 0.4mL/min) with the exception of porous media. In this section, five artificial sandstone consolidated cores, which had very close geophysical properties as shown in Table 3, were used to ensure the 6


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results could be meaningfully compared. The basic theory of the relative permeability is as follows.

݂୭ (ܵ୵ ) = ‫ܭ‬୰୭ = ݂୭ (ܵ୵ )

ୢ௏౥ (௧) ୢ௏(௧) ୢ[ଵ/௏(௧)] ୢ{ଵ/[୍·௏(௧)]}

‫ܭ‬୰୵ = ‫ܭ‬୰୭ · ‫=ܫ‬

ொ(௧) ொ౥

ఓ౭ ଵି௙೚ (ௌ౭ ) ఓ౥

·

·

௙೚ (ௌ౭ )

∆௉౥ ∆୔(௧)

(3) (4) (5) (6)

where, fo(Sw) is the oil fraction; Vo(t) is the dimensionless oil recovery (PV); V(t) s the dimensionless fluid recovery (PV); Kro is the oil relative permeability; Krw is the water relative permeability; I represents the relative injectivity of the fluids; Qo the initial oil production rate (mL/s); Q(t) the oil production rate (mL/s) at time of t; ∆Po the initial differential pressure (MPa) and ∆P(t) the differential pressure (MPa) at time of t. 3. RESULTS AND DISCUSSION 3.1 Interfacial tensions (IFTs) At the end of the economic life of waterflooding, a large volume (half to two-thirds) of crude oil is trapped in porous media in the forms of droplet or ganglia due to the significant capillary forces induced by the high oil/water IFTs and narrow pores. Therefore, the reduction of the IFTs by using chemical additives (surfactant, alkali, organic solvent, etc.) is thought to be the most effective way to further unlock the remaining reserves. Figure 3 shows the measured IFTs between the crude oil and different ion brines as a function of salinity. The results indicated that the IFTs of the evaluated crude oil/brine systems displayed quite similar tendency and the majority of the IFTs values fell into the range of 1-6 mN/m. The most notable responses on IFT curves were observed at the salinity between 0.2-0.5 wt%, which corresponded to the optimum salinity in our case. Moreover, as illustrated in Fig. 3, the lowest oil/water IFTs were generated when the ions of CaCl2 was used followed by MgSO4 and NaHCO3.

7


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Table 2 Parameters of the porous medium and brine used in oil displacement tests NaCl (wt%)

NaHCO3 (wt%)

CaCl2 (wt%)

MgSO4 (wt%)

K2SO4 (wt%)

0.01

0.2

2

0.01

0.2

2

0.01

0.2

2

0.01

0.2

2

0.01

0.2

2

L (cm)

8

8

8

8

8

8

8

8

8

8

8

8

8

8

8

D (cm)

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

2.5

PV (mL)

13.5

13.2

14.0

14.8

14.2

14.0

13.5

13.7

14.1

13.3

12.9

12.9

14.2

13.6

13.9

K (mD)

149

132

144

162.3

178.4

147.9

129.5

127.5

142.4

123.5

101.3

132.4

136.7

156.2

128.5

Soi (%)

79.8

76.7

77.6

75.3

73.3

76.9

75.2

71.5

76.4

78.3

80.2

76.4

77.6

78.0

81.8

Table 3 Geophysical properties of the cores used in unsteady-state core flooding tests Core number

Ion type

Diameter (cm)

Length (cm)

K (mD)

Pore volume (cm3)

Connate water saturation

Initial oil saturation

Swc (%)

Soi (%)

Porosity (%)

200-20

K2SO4

3.85

7.50

140.8

14.01

16.05

0.326

0.674

200-21

NaHCO3

3.88

7.62

157.8

15.47

17.18

0.328

0.672

200-24

NaCl

3.89

7.61

146.9

14.46

16.00

0.292

0.708

200-1

CaCl2

3.84

8.05

157.8

18.60

19.96

0.274

0.726

200-15

MgSO4

3.85

7.60

148.8

18.45

20.86

0.329

0.671

8


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This tendency is partially consistent with that reported by Lashkarbolooki et al.43 The distributions of the natural surfactants and acidic/basic species of crude oil at the oil water interface are altered caused by the presence of ions in the system. As the salinity decreased from HS level, the surface-active compounds as mentioned above would transfer from the bulk oil phase to the oil water interface, which thus lead to the observed decrease of the IFTs. This response is so-called "salting-in" effect.4,

43

Regarding to the behaviors of divalent cations (Ca2+ and Mg2+) in IFTs reduction, it can be interpreted by the fact that the affinity of divalent cations to polar species is higher than that of monovalent cations due to the electrostatic effect, which therefore leads more surface-active species to assemble at the oil water interface. With the salinity further decreasing, the IFTs of the studied systems increased again. It is believed that this interesting response of IFTs to salinity was mainly caused by the dissolved hydrocarbons (polar species entering the water phase) in water phase, and subsequently made the ions at the interface insufficient to present LSE as claimed by Moeini et al.44, 45 A schematic representation of this process is shown in Fig. 4, which can assist in understanding the complex mechanisms involved in this process. Unfortunately, it is challenging to accurately determine this partitioning to the interface. The obtained results in this section have not been adequate to identify the effects of anions at the interface. 6

MgSO4

k2SO4

NaCl

CaCl2

NaHCO3 4

IFT (mN/m)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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2

0 0.01

0.1

1

10

Salinity (wt%)

Figure 3. Oil/water IFTs as a function of salinity 9


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Figure 4. Schematic representation of the interfacial behaviors 3.2 Interfacial dilational rheology A widely held brief is that the measurement of interfacial dilational rheology is more convincing to represent the dynamic response of the interface to environment than that of IFTs.46 Figure 5 plots the interfacial dilational moduli (E) of the oil water interfaces as a function of salinity at a frequency of 0.08Hz. Consistent with the variations of IFTs (Fig. 3), the measured interfacial dilational moduli (E) also presented a salinity- and ion-dependent behavior and the maximum E was observed when the salinity of 0.2 wt% was used, as revealed by the profiles shown in Fig. 5. However, it must be pointed out that the sequence of E upon ions was different from that of the IFTs if Fig. 5 and Fig. 3 were compared. That's probably because E is a complex element taking the thermodynamic and kinetics characteristics of the interface into consideration, and represents the viscoelastic properties of the interface as reported by Powell and Chauhan.46, 47 In contrast, the equilibrium IFT essentially 10


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represents the assembling behaviors of the polar components at the interface. As illustrated in Fig. 5, for this crude oil, NaHCO3 produced the largest E within the whole evaluated salinity range. As a result of the basicity of the NaHCO3 solution (Table S1), the acidic components (petroleum acids) near the interface were in-situ saponified. The sequential assembly of the produced surfactants at the oil water interface resulted in a further close-packed and viscoelastic adsorption layer. With regard to MgSO4, relying on the electrostatic effect of the divalent ions of Mg2+ and SO42- with the acidic and basic components in the crude oil, the transfer of these species from the bulk to the oil-water interface was therefore promoted. On the basis of the collected data, it can be inferred that sulfate (SO42-) anions also played a crucial role in LSE. On the contrary, the chloride (Cl-) anions (CaCl2 and NaCl) had no significant LSE at the interface, probably due to the weak affinity of Cl- and Ca2+ toward the these polar compounds compared to that of Mg2+ and SO42-.48 Figure 6 presents the measured E of the oil brine interface as a function of frequency. It was observed that the magnitude of E increased gently with the frequency at a constant salinity of 0.2 wt%, proving its oscillation frequency-dependence. This positive response also validated the suitability of the low frequency imposed to our systems, otherwise limited exchanges between the bulk solution and interface and thus non-frequency-dependence will be observed.46, 49, 50 Interfacial dilational modulus (mN/m)

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NaHCO3

250

CaCl2 MgSO4

200

K2SO4 NaCl

150

100

50

0 0.01

0.1

1

10

Salinity (wt%)

Figure 5. Interfacial dilational modulus as a function of salinity (Oscillation frequency=0.08Hz) 11


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Interfacial dilational modulus (mN/m)

Energy & Fuels

250

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NaHCO3 CaCl2 MgSO4

200

K2SO4 NaCl

150

100

50 0.00

0.02

0.04

0.06

0.08

0.10

Frequency (Hz)

Figure 6. Interfacial dilational modulus as a function of frequency (Salinity: 0.2 wt%) 3.3 Emulsion properties As we confirmed previously,4 emulsification is one of possible mechanisms in LSE; nevertheless, the relevant evidence is scarce in the literature. Mahzari and Sohrabi found that that when the brine salinity was reduced to below 2000 ppm, water-in-oil (W/O) dispersions would be spontaneously formed.51, 52 Alotaibi and Yousef briefly introduced the effect of ions on the emulsion particle size in their published work.37 In this paper, primary attention was given to the emulsifiability of different ions in bulk through a visual examination. Based on the obtained results, the optimum salinity of 0.2 wt% was used throughout these tests. Figure 7 collects the images of the mixtures over time. The ions from left to right in each image are NaHCO3, CaCl2, K2SO4, MgSO4 and NaCl. As shown in Fig. 7, the prepared O/W emulsions in the oil water ratios from 1:9 to 3:7 were quite unstable, demonstrated by the rapid phase separation. A close examination on the emulsions revealed the differences of ions in emulsification. After 1 h the emulsions prepared with NaCl and CaCl2 were optically transparent. In contrast, the other three emulsions prepared with NaHCO3, MgSO4 and K2SO4, respectively, remained opaque, especially in the oil water ratio of 3:7. With the further increase of oil fraction, the formed emulsion was reversed to W/O type, which seemed more stable than the O/W emulsions as shown in Fig. 7. The transition of the emulsion type was evidenced largely by viscosity and color of the mixtures. of It should be noted that for NaHCO3 the oil water ratio for phase reverse was 5:5. This 12


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was not expected relative to other systems, and the test was repeated to confirm results reliability and reproducibility. This fact is believed to associate with the chemical reactions between petroleum acids and NaHCO3. Further investigation of the LSE from the point of emulsification upon different ions is in progress in our group. It has been agreed that the occurrence of emulsion destruction is mainly impacted by several processes including creaming or sedimentation, Ostwald ripening, and droplet coalescence.50, 53 Of the above processes, coalescence is admitted to be governed by surface viscoelasticity, whereas Ostwald ripening is largely controlled by the solubility of dispersed phase and its volume fraction. In other words, high interfacial viscoelasticity of oil water interface leads to high stability of the formed emulsion, as verified in this study.

13


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Figure 7. Images of the oil/brine mixtures (salinity: 0.2 wt%) 3.4 Wettability alteration Wettability alteration is considered as one of the predominant mechanisms in LSE. The occurrence of wettability alteration in LSWF is usually complicated by the interactions between oil, brine and minerals, and the kinetics is strongly dependent on the compositions of the involved substances. As we summarized in the introduction section, the wettability alteration of the rock during LSWF can be caused by MIE, "salting-in" effect, DLE, mineral dissolution, etc.16 Figure 8 compares the contact angle of an oil drop formed on the sandstone slide before and after exposing to different ions. For comparison, the salinities of 0.01 (ultra LS) and 2 wt% (HS) were also involved. After aging in the crude oil, the slide surface was changed to oil wetting as a result of the adhesion of polar species on the surface through Van der Waals, cation exchange, Ligand bridging, etc.12,

14, 54

Fortunately, the surface affinity of the sandstone was successfully converted to water wetting after soaking in brines for a certain time. As shown in Fig. 8, the value of the contact angle gradually decreased with the exposure time before finally reaching equilibrium. The LSE of wettability alteration was supported by the observed results, i.e., the salinity of 0.2 wt% led to the most significant wettability alteration of the rock towards water-wetting for most of the tests ions with the exception of K2SO4, which produced the similar water-wet states at the salinities of 0.2 and 0.1 wt% under the same experimental conditions. The magnitudes of the contacted angle reserved (θinitial-θeq) for the tested ions are shown in Fig. 8 (bottom right). It was found that the divalent ions (Mg2+, Ca2+ and SO42-) caused more significant wettability change than the monovalent ions. The interpretation to this finding can be that the presence of the divalent ions first bond with the adsorbed polar components and then detach them from the rock surface. This reaction altered the surface affinity toward a water wetting state. As a result of the charge density and valency, divalent ions are expected to be more effective than monovalent ions in replacing the polar species.3, 15 However, it should be highlighted that this is not the only reason behind the wettability alteration in our case, deep studies are required to gain the underlying mechanisms especially at 14


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the ultra-low salinities. 160

160

CaCl2

Contact angle (°)

Contact angle (°)

120

80

120

80

40 0

4

8

12

16

0

4

8

Time (d)

12

16

Time (d)

160

160

0.01 wt% 0.2 wt% 2 wt%

0.01 wt% 0.2 wt% 2 wt%

NaCl

Contact angle (°)

K2SO4 Contact angle (°)

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MgSO4

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Contact angle reversed (o)

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Time (d)

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Energy & Fuels

12

0

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16

Time (d)

Time (d)

Figure 8. Contact angle variation as a function of exposure time 3.5 Oil displacement tests In this section, a total of 15 oil displacement tests were conducted in order to study the displacement behaviors of different ions during LSWF and also to relate the bulk properties tested above. Figure 9 shows the oil recovery factors of different brine injection tests. The bottom right one of Fig. 9 compares the response of oil recovery 15


Energy & Fuels

factor to different ions at a constant salinity of 0.2 wt%. As shown in Fig. 9, the oil recovery factors gently increased with the PV of the injected brines until no additional oil was produced after 4 PV. LSE was clearly observed from Fig. 9, which means that the 0.2 wt% brine (LS) yielded the highest oil recovery compared to HS and ultra-low salinity brines. Nevertheless, for a certain ion, the response of the oil recovery factor to salinity were quite different as revealed by the gap between the ultimate recovery factors on the profiles, suggesting the salinity-ion-dependent behaviors of LSWF. In addition, the highest oil recovery was achieved by injecting 0.2 wt% of NaHCO3 followed by MgSO4. This observation is consistent with the tendency of the static properties of interfacial viscoelasticity and emulsification as shown in Fig. 5 and Fig. 7, respectively. Based on these results, it can be generally concluded that HCO3-, Mg2+ and SO42- are PDIs for LSE. 60

60

NaCl

NaHCO3 50

Oil recovery factor (%)


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CaCl2

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Energy & Fuels

40

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0.01 wt% 0.2 wt% 2 wt%

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MgSO4 NaCl NaHCO3

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Figure 9. Oil recovery factor profiles versus injected PV 3.6 Relative permeability curves The oil water flow behaviors in porous media were further investigated using unsteady-state coreflooding tests in order to understand the relationship between oil recovery and interfacial behaviors. Figure 10 shows the obtained relative permeability of oil (Kro) and water (Krw) phases. Indeed, the comparison of the relative permeability curves using HS and LS brines have been conducted before.31, 55 The injection of LS brine resulted in the increase of Kro and decrease of Krw. Thus, in the current work, the primary focus was placed on the influence of ion types on the Kro and Krw instead of salinity. As shown in Fig. 10, the injection of NaHCO3 solution significantly improved the oil water relative permeability compared to other ions, i.e. increasing Kro and decreasing Krw. As for MgSO4 and K2SO4, it is interesting that at low Sw, the Kro of MgSO4 injection was smaller than that of K2SO4 injection; however, after a certain Sw, the Kro of MgSO4 injection became larger. Moreover, the Kro of NaCl and CaCl2 injections was notably smaller than that of other ions. It is widely accepted that with the increase of Sw during secondary waterflooding, the continuous oil phase (oil column) would be broken into oil droplet or oil ganglia when it passes through pore throat, namely "snap-off" effect. This subsequently leads to the rapid decrease of Kro and oil trapping in porous media. However, several works have shown that the critical capillary number for oil drop breakup increased with the viscoelasticity of the interface.30, 56, 57 In other words, the viscoelastic interfaces can 17


Energy & Fuels

hinder or at least delay the breakage of the oil column as depicted in Fig. 11, which consequently results in favorable variation of the relative permeability and oil recovery. As indicated in Fig. 5 and Fig. 6, the solution of NaHCO3 showed the highest viscoelasticity followed by MgSO4 solution for a given crude oil. Therefore, these two solutions are anticipated to present the most favorable relative permeability and highest oil recovery factor. This conclusion was well supported by the results of Fig. 9 and Fig. 10. Moreover, it should emphasized that other mechanisms such as IFT reduction, wettability alteration, etc., may be also involved. Therefore, from the above investigations, we concluded that the LSE is true and predominately caused by the ions of HCO3-, Mg2+ and SO42- (PDIs). 1.0

0.8

Relative permeability

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Kro K2SO4 Krw K2SO4

0.6

Kro NaHCO3 Krw NaHCO3 Kro NaCl Krw NaCl

0.4

Kro MgSO4 Krw MgSO4 Kro CaCl2

0.2

Krw CaCl2

Salinity: 0.2 wt%

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0.6

0.7

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Sw

Figure 10. Relative permeability curves of the tested crude oil/brine systems

18


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Figure 11. Schematic illustration of oil phase passing through pore throat 4. CONCLUSIONS Understanding the roles of individual ion and salinity in LSE benefits the use of LSWF in EOR. Thus, this work presented an experimental investigation of ion influences on oil/brine/rock interfacial behaviors, oil recovery performance and relative permeability. Based on the obtained results, the following conclusions can be drawn: 1. The ITFs between the crude oil and brine are not sensitive to ions; the generated oil/water IFTs ranged from 1-6 mN/m, regardless of ion type and salinity. Thus, it is believed that IFT reduction is not the mechanism or at least not key mechanism for LSE. 2.

The

dilational

modulus

of

oil

water

interface

presented

a

strong

salinity-ion-dependence due to the adsorption of active species at the interface. Of the tested ions, HCO3-, Mg2+ and SO42- constructed the most viscoelastic oil water interfaces compared to other ions. 3. The viscoelastic interfaces lead to the enhanced stability of the prepared emulsions due to the resisted coalescence of the oil droplets. 4. The wettability alteration in LSE was indeed observed in our work. The initial oil-wet sandstone surface was successfully reversed to water-wet state after exposing to LS brine as a result of detachment of polar species from the surface. Deep studies are required to determine the behind reasons. 5. The viscoelastic oil water interfaces hindered or delayed the breakage of the oil column, thus leads to the improvement of the relative permeability and oil recovery. The roles of HCO3-, Mg2+ and SO42- in LSE as PDIs are highlighted in this work. 6. The LSE is true but the underlying mechanisms are more complex than expected, which depends not only on fluid/rock mineral properties and interactions but also ion type and composition/ratio. The dominance of the proposed mechanisms should closely relate to the conditions of a specific reservoir. Thus, a thorough screening test must be conducted before performing any LSWF pilot tests.

AUTHOR INFORMATION 19


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Corresponding Authors *B. Wei. Email: [email protected] Notes The authors declare no competing financial interests.

ACKNOWLEDGMENTS The authors gratefully acknowledge the financial support of the National Key Basic Research Program of China (2015CB250904) and Natural Science Foundation of Sichuan Province (2017JY0122). The authors also thank the anonymous reviewers for their valuable comments.

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