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EOR by Low Salinity Water and Surfactant at Low Concentration: Impact of Injection and In-situ Brine Composition Hamid Hosseinzade Khanamiri, Ida Baltzersen Enge, Meysam Nourani, Jan Åge Stensen, Ole Torsæter, and Nanji Hadia Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b02899 • Publication Date (Web): 23 Feb 2016 Downloaded from http://pubs.acs.org on February 25, 2016

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EOR by Low Salinity Water and Surfactant at Low Concentration: Impact of Injection and In-situ Brine Composition

Hamid Hosseinzade Khanamiri1 *, Ida Baltzersen Enge1, Meysam Nourani2, Jan Åge Stensen3, Ole Torsæter1, Nanji Hadia4 1

Department of Petroleum Engineering and Applied Geophysics, Norwegian University of Science and

Technology (NTNU), 7491 Trondheim, Norway; 2

Department of Chemical Engineering, Norwegian University of Science and Technology (NTNU), 7491

Trondheim, Norway; 3

Sintef Petroleum Research, 7031 Trondheim, Norway;

4

Institute of Chemical and Engineering Sciences, A*Star, Singapore

*

Corresponding author, Email address: [email protected]

Abstract Low salinity water (LSW) and low salinity surfactant (LSS) coreflooding experiments were performed to study the impact of ionic composition on oil recovery from aged Berea sandstone cores. Surfactant adsorption in packed beds, contact angles, interfacial tension (IFT), critical micellar concentration (CMC) and end-point relative permeabilities were used to better understand wettability alteration. In the samples aged with the same in-situ brine with (Ca2++Mg2+)/Na+=0.033, both end-point relative permeabilities of LSW flooding and contact angles showed LSW with only sodium chloride made the samples more water wet than LSW with divalent-contained brines. Oil recovery was also highest in LSW injection with only sodium chloride. In tertiary LSS of the same core samples, according to both flooding and contact angles, 1 ACS Paragon Plus Environment

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LSS with only sodium chloride showed more water wetness. Characterization measurements showed that at higher Ca2+/Na+ ratio, CMC and IFT were lower whereas surfactant adsorption was higher. Further, at similar conditions, LSW and LSS made the core sample more water wet than high salinity water (HSW) and high salinity surfactant (HSS). At low surfactant concentration, LSS recovered as much oil as HSS did.

1. Introduction Effect of low ionic strength water injection on oil recovery is extensively investigated and potentials of this technique have been approved in laboratory experiments.1-5 Ligthelm et al. (2009) believed expansion of electrical double layer between negatively charged oil particles and negative sites on rock mineral mobilizes oil.6 Austad et al. (2010) suggested that local increase in pH at the clay surface, upon lowering the ionic strength, is caused by desorption of active cations, especially Ca2+, which is substituted by H+ from the water. A fast reaction between OH- and the adsorbed acidic and protonated basic material causes oil desorption from clay.7 Lager et al. (2006), however, believed that multicomponent ionic exchange (MIE) mobilizes oil. Injection of low salinity brine is believed to result in MIE where polar oil components and organo-metallic complexes are replaced by uncomplexed cations.8 Water Micro-Dispersions9 and fines migration2 are other proposed mechanisms for low ionic strength water injection. In addition to these efforts to recognize mechanisms of this enhanced oil recovery (EOR) method, there has been research to combine the technique with other EOR techniques, mainly chemical methods as a low saline environment would create favorable conditions for polymer10, 11 and surfactant injection12-14. Surfactants facilitate oil mobilization by lowering the capillary forces due to reduction in the IFT between oil and aqueous phases. It can also mobilize oil by wettability alteration. Combination of

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low salinity water injection with surfactant injection seems to have environmental and economic advantages. Alagic and Skauge (2010) performed a series of core flooding experiments and reported high tertiary oil recovery by surfactant injection after establishing a low saline environment by injection of low salinity water. An increase in salinity results in formation of water-in-oil microemulsion at which surfactant tends to stay in oil phase. This could be avoided at lower ionic strengths where oil-in-water microemulsion forms. They also observed lower tertiary oil recovery by surfactant without a low salinity preflush.12 Alagic et al. (2011) reproduced similar results on longer core samples.13 Tichelkamp et al. (2014 and 2015) conducted a comprehensive study on the feasibility of achieving ultralow IFT between sodium dodecylbenzenesulfonate (SDBS) and sodium dioctylsulfosuccinate (Aerosol OT or AOT) surfactant solutions and different oil phases at low salinity. They measured IFTs as low as 0.032mN/m between AOT solutions and crude oils at low salinity. They also investigated the effect of calcium cations (Ca2+) on the IFT values and observed lower IFT between the four different crude oils and low ionic strength surfactant solutions while a small amount of Ca2+ was added to the low salinity SDBS solution. In case of low salinity AOT solutions, IFT was reduced for two of the crude oil samples while it was increased for the other two samples.15, 16 An advantage of surfactant injection at low ionic strength is reduction in surfactant retention by adsorption.17-19 This may create opportunity to inject surfactant at lower concentration. Nourani et al. (2014) investigated crude oil desorption from silica and aluminosilicate surfaces upon their exposure to low salinity water and surfactant solutions by means of quartz crystal microbalance (QCM). They observed increase in oil desorption and change of wettability towards more water wet after exposure of the surfaces to low salinity water and surfactant solutions. They also


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reported increase in surfactant concentration had more pronounced effect on wettability alteration of the aluminosilicate surfaces than of silica surfaces.20 Moreover, comparison of rock-fluid interactions in LSS and optimal salinity surfactant suggests rock-fluid interactions in LSS are more favorable than in optimal salinity surfactant such that although the capillary number is higher in LSS, the oil recoveries are as high as in optimal salinity.18, 21 The objective of this work was to investigate the effect of composition of aging brine and injection brine on the performance of the combined low salinity water and surfactant injection at low surfactant concentration. Cores were aged with brines of different composition and flooded with the diluted version of the same in-situ brine. Further, a set of cores were aged with identical brine and each flooded with a different brine composition during water and surfactant injection. It was attempted to understand the effect of divalent cations in low salinity water and surfactant through IFT, surfactant adsorption, CMC, contact angle measurements and coreflooding experiments.

2. Material 2.1.

Rock

The core plugs were extracted from a Berea sandstone block. Bulk mineral composition of two random samples were measured by X-ray diffraction (XRD) and shown in Table 1. Length and diameter of the cores were 10cm and 3.8cm, respectively. Porosity, corrected air permeability (Kair) and irreducible water saturation (Swirr) are given in Table 2. Figure 1 represents a micro scale image of the rock sample. Images were taken by x-ray in a micro-CT machine. Size distributions of pore body, throat and body/throat ratio were extracted from 3D tomography


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images (Table 3). Histograms of relative frequency of these parameters are also illustrated in Figure 2. Method of estimating these parameters has been previously published.22

2.2.

Brines

Rock samples were saturated and aged with different high salinity brines (HSW brines in Table 4). The brines had equal ionic strength of 0.556mol/L but different ionic compositions. Low salinity injection brines (LSW) were 10-fold diluted version of the HSW brines (Table 4). The diluted brines were also used to prepare the low salinity surfactant solutions.

2.3.

Oil

A dead crude oil was used for preparation (drainage and aging) and EOR injection experiments. Properties of crude oil are given in Table 5.

2.4.

Surfactant

Sodium dodecylbenzenesulfonate (SDBS), Sigma Aldrich, was used as received. Table 1: Bulk mineral composition of two random Berea samples measured by X-ray diffraction (XRD) composition [wt %] mineral

sample 1

sample 2

quartz

91.75

92.5

plagioclase

0.78

0.94

alkali feldspar

6.56

5.22

diopside

0.9

1.34


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Table 2: Physical properties of core samples Test

ᴪ

Kair

Porosity

Swirr

(mD)

(%)

(%)

A

309

15.5

23.3

HSW-Na

B

391

15.9

22.9

HSW-NaCa

C

282

15.3

25.2

HSW-SFW

D

307

15.9

27.7

HSW-SFW

E

286

16.1

28.0

HSW-SFW

ᴪ

Saturation brine

Composition of initial saturation brines are given in Table 4.

Figure 1: A micro-CT image of Berea rock sample (2mmx2mm); Black is the pores and grey is the grains.

Table 3: Maximum, minimum and average values of pore geometry parameters Parameter

Max

Min

Mean

body size (µm)

262.4

4.7

30.4

throat size (µm)

62.1

4.1

9.3

body/throat ratio

30.3

0.4

3.2


50 40 30 20 10 0

relative frequency (%)

0

20 40 60 80 pore body size(µm)

100

5

30

60 50 40 30 20 10 0 0

10

15

20

25

pore throat diameter (µm)


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80 60 40 20 0 0

5 10 15 body/throat ratio

20

Figure 2: Relative frequency of pore body, throat and body/throat size distribution

Table 4: Composition of the brines Brine

NaCl,

CaCl2.2H2O,

MgCl2.6H2O,

[g/L]

[g/L]

[g/L]

ᴪ

TDS,

[mg/L]

ionic

ᴪ

2+

strength, [mol/L]

HSW-SFW

29.250

2. 210

0.305

31061.0

0.5560

0.0330

HSW-NaCa

30.875

1.362

_

31903.1

0.5560

0.0175

HSW-Na

32.500

_

_

32500.0

0.5561

0

LSW-SFW

2.925

0.221

0.030

3106

0.0556

0.0330

LSW-NaCa

3.087

0.136

_

3190

0.0556

0.0175

LSW-Na

3.250

_

_

3250

0.0556

0


+

M /M , [mol/L]/ [mol/L]

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ᴪ

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TDS stands for total dissolved solids and M2+/M+ is the molar ratio of divalent to monovalent cations.

a

Table 5: Chemical composition and physical properties of crude oil component

composition [wt %]

Saturates

61.19

Aromatics

32.42

Resins

4.93

Asphaltenes

1.46

physical property

value

TAN [mg KOH/g]

1.08

TBN [mg KOH/g]

1.16±0.35

3

Density [g/cm ] @ 15°C

0.8582

@ 60°C

0.8252

API gravity [°API]

33.5

Viscosity [mPas] @ 15°C

19.90

@ 60°C

4.07

a

Data taken from ref 15.

3. Experimental Section 3.1.

Preparation of core material

The primary drainage was performed using porous plate method to obtain the irreducible water saturation (Swirr). The cores samples (Table 2) were first saturated with different HSW brines (Table 4) under vacuum. Samples were then left in a sealed container at room conditions for about two days after which they were mounted in a core holder with a ceramic porous plate at the outlet face of the core and the crude oil (Table 5) was pressurized at the inlet face. The pressure was increased from atmospheric to gauge pressure of 3.5bar in a period of about 3-4 weeks. Pressure increments 8 ACS Paragon Plus Environment

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were maximum 0.5bar. The drainage by porous plate is intended to obtain uniform immobile (irreducible) water saturation in the core samples. The obtained irreducible water saturations (Swirr) are given in Table 2. Changes in water saturation at different pressures are illustrated in Figure 3. Pressure was increased when the water production was very slow. Therefore the curves in Figure 3 may be good approximation of drainage capillary pressure. The samples were then aged with crude oil (Table 5) at 80°C in sealed containers to alter the wettability toward being more oil wet. All samples were aged for three weeks.

Drainage pressure (bar)

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4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0

A B C D E

0.0

0.2

0.4

Sw

0.6

0.8

1.0

Figure 3: Drainage pressure versus saturation changes in the drainage using ceramic porous plate for cores A-E

3.2.

Coreflooding

Injection experiments were performed at a temperature of 60°C and a back-pressure of 4.5bara. Fluid reservoirs were placed inside the heating cabinet for thermal equilibration prior to injection. Schematic diagram of the injection apparatus is illustrated in Figure 4. Surfactant solutions were prepared using previously heated brines at 60°C and kept warm prior to and during the experiments. Secondary low salinity water (LSW) and tertiary low salinity surfactant (LSS) solutions were injected in all experiments. About 10 pore volume (PV) of each LSW and LSS solutions were injected in each experiment. Injection rate was maintained at 12ml/hr which was approximately equivalent to pore velocity of 5.2ft/d. The injections were performed at higher 9 ACS Paragon Plus Environment

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equivalent pore velocity to avoid any possible end-effect during LSW flooding. LSWs with ionic strength of 0.0556mol/L were prepared by 10 fold dilution of HSW brines (Table 4). Surfactant solutions were prepared by dissolving 500mg/L SDBS in the same diluted brines. In all the flooding experiments, the brine in LSS injection had the same ionic composition as in the LSW. The only difference was presence of surfactant in the LSS solution. Details of coreflooding experiments are given in Table 6.

Figure 4: Schematic diagram of the coreflooding apparatus; 1) Pump reservoir, 2) Positive displacement pump, 3, 4 and 5) fluid reservoirs, 6) Manifold, 7) Check-valve, 8) Core holder, 9) Heating cabinet, 10) Back-pressure regulator, 11) Effluent collector, 12) Equalizer valve, 13) Differential pressure transmitter, 14) Computer Table 6: Details of coreflooding experiments Test

saturation

Injection 1,

Injection 2, LSS

brine

LSW

A

HSW-Na

LSW-Na

SDBS in LSW-Na

B

HSW-NaCa

LSW-NaCa

SDBS in LSW-NaCa

C

HSW-SFW

LSW-SFW

SDBS in LSW-SFW

D

HSW-SFW

LSW-NaCa

SDBS in LSW-NaCa

E

HSW-SFW

LSW-Na

SDBS in LSW-Na


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3.3.

Fluid-fluid interaction measurements

3.3.1. Surfactant solubility in different brines. Surfactant solubility tests were conducted to determine the concentration at which SDBS precipitation was observed in low salinity brines. Solutions with SDBS concentrations of 300, 500, 1000 and 3000mg/L were prepared and observed for several days at 60°C. Results of these tests were summarized in Table 7. LSW-Na did not show visually-detectable precipitation in the 4 SDBS concentrations while precipitation was observed in LSW-NaCa and LSW-SFW at SDBS concentrations of 1000 and 3000mg/L during the first 24 hours. Since no precipitation was observed at 500mg/L of SDBS in none of the diluted brines, this concentration was selected for injection experiments. Table 7: SDBS solubility in low salinity brines at 60°C; observations for 48 and 72 hours were the same as for 24 hours. SDBS, Brine

24 hours mg/L 300

no precipitation

500

no precipitation

1000

no precipitation

3000

no precipitation

300

no precipitation

LSW-NaCa &

500

no precipitation

LSW-SFW

1000

precipitation

3000

precipitation

LSW-Na

3.3.2. Critical Micellar Concentration (CMC). Since low surfactant concentration of 500mg/L was used in the LSS coreflooding experiments, CMC of SDBS at different ionic strengths both in presence and absence of calcium were measured.23 Measurements showed that the mentioned concentration was several times higher than the CMC. CMC was about 105mg/L at NaCl 11 ACS Paragon Plus Environment

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concentration of 0.0556mol/L; the ionic strength of the LSS flooding experiments. Addition of calcium to the solution reduced the CMC to 65mg/L at ionic strength of 0.0556mol/L and Ca2+/Na+ ratio of 0.022. 3.3.3. Interfacial tension (IFT). IFT between crude oil and surfactant solutions with different salinity and ionic compositions were measured by a Spinning Drop Tensiometer at 60°C. The surfactant concentration was 500mg/L in all the IFT measurements.

3.4.

Rock-fluid interaction measurements

3.4.1. Surfactant adsorption in packed bed. LSW was injected with rate of 0.4ml/min through a packed bed of synthetic silica (silicon dioxide) particles with average grain size of 110µm. Diameter and length of the cylindrical bed were 1 and 3cm, respectively. After saturation of the packed bed with LSW, injection was switched to LSS with 500mg/L SDBS in the solution. Inline UV measurement was performed at the effluent. Experiments were performed at 60°C. Details of adsorption tests are given in Table 8. Table 8: SDBS adsorption tests in packed bed at 60°C Test

Saturation

Surfactant injection

brine (LSW)

(LSS)

AE

LSW-Na

SDBS in LSW-Na

BD

LSW-NaCa

SDBS in LSW-NaCa

C

LSW-SFW

SDBS in LSW-SFW

Tests AE, BD and C respectively resemble the adsorption in coreflooding tests A and E; B and D; and C. Although there is a large difference between an artificial porous media and an aged natural porous media, the adsorption experiments show the effect of brine composition (ratio of


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Ca2+/Na+) on surfactant adsorption by isolating other parameters. The observed trends would be helpful in understanding the effect of divalent cations, but the values of adsorption cannot be generalized to the coreflooding experiments due to presence of crude oil and different wettability conditions in the coreflooding. 3.4.2. Contact angle measurements. Silica-coated crystals were used as the solid surface. The crystals had high smoothness in order to be used in quartz crystal microbalance (QCM)20 measurements. The purpose of selecting these crystals for contact angle measurements was to minimize the possible effect of surface roughness. Fresh crystals were cleaned before the experiments. The cleaning procedure includes: rinsing with toluene, rinsing with deionized water, air-drying, leaving crystals in solution of 20000mg/L sodium dodecyl sulfate for about 30min, rinsing with deionized water and air-drying again. Five experiments were designed to better understand wettability alteration in the five core flooding experiments (Table 9). Tests A-E were respectively similar to coreflooding tests of A-E in terms of the aging and injection fluids. Contact angle was measured between a deionized water drop and the crystal surface. Summarized procedure of experiments is as follows. Table 9: Matrix of contact angle tests; crystals were aged in HSW before flow of crude oil. LSW and LSS were flowed over crystals after aging in crude oil. SDBS concentration in LSS solutions was 500mg/L. Test

HSW (aging)

LSW

LSS

A

HSW-Na

LSW-Na

SDBS in LSW-Na

B

HSW-NaCa

LSW-NaCa

SDBS in LSW-NaCa

C

HSW-SFW

LSW-SFW

SDBS in LSW-SFW

D

HSW-SFW

LSW-NaCa

SDBS in LSW-NaCa

E

HSW-SFW

LSW-Na

SDBS in LSW-Na


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1. Flow of HSW and 2hr aging in HSW at room temperature 2. Flow of crude oil, leaving the crystals in perpendicular position at room temperature in order to let the oil film thins out. 3. Measuring the contact angle before aging by a deionized water drop on the surface 4. Aging the crystals in crude oil at 70°C for about three days 5. Leaving the crystals in perpendicular position at room temperature 6. Measuring the contact angle after aging 7. Flow of low salinity water (LSW) and 2hr aging in LSW at room temperature 8. Measuring the contact angle after LSW 9. Flow of low salinity surfactant (LSS) and 2hr aging in LSS at room temperature 10. Measuring the contact angle after LSS

4. Results Oil recoveries in the coreflooding experiments A-E were summarized in Table 10. The aging brines in tests A, B and C had different compositions and in every test the diluted aging brine was injected in LSW and LSS. The aging brines in tests C, D and E were the same, but the injection brines in the LSW and LSS were different in these three tests. Test C was the common experiment in the two groups of flooding experiments. The recovery and pressure drop profiles during LSW and LSS injection are shown in Figure 5. Figure 6 shows the end-point relative permeabilities in LSW and LSS. IFT of the crude oil with different LSS and NaCl solutions of different salinities are illustrated in Figure 7. Contact angles of tests A-E are shown in Figure 8. Figure 9 shows the results of three surfactant adsorption tests in packed beds. Figure 10 shows the measured CMCs at different salinities and Ca2+/Na+ ratio. 14 ACS Paragon Plus Environment

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Table 10: Recoveries in different injections based on original oil in place (%OOIP) recovery (%OOIP)

Residual oil saturations (Sor)

M2+/M+ in in-situ

M2+/M+ in LSW

BT time

LSW,

LSW,

LSW,

HSW brine

& LSS brine

(PV injected)

BT

after BT

final

A

0

0

0.41

47.8

3.7

B

0.0175

0.0175

0.34

42.0

C

0.0330

0.0330

0.33

D

0.0330

0.0175

E

0.0330

0

Test

LSS

Total

51.5

3.0

54.5

37.2

34.9

10.9

52.9

5.1

58.0

36.3

32.4

44.2

3.9

48.1

5.4

53.5

38.8

34.8

0.32

45.0

3.8

48.8

2.4

51.2

37.0

35.3

0.39

50.0

7.7

57.7

6.2

63.9

30.5

26.0

BT stands for breakthrough and M2+/M+ is the molar ratio of divalent to monovalent cations.


(Sor)LSW

(Sor)LSS

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60

700

B, Ca/Na=0.0175

400

C, (Ca+Mg)/Na=0.033

30

300 20

200

10

100 0

0 0

5

10 PV injected

15

20

70

700

60

600

50

500 C, (Ca+Mg)/Na=0.033

40

400

D, Ca/Na=0.0175 E, Ca/Na=0

30

300

20

200

10

100

0

Pressure drop (mbar)

Recovery factor (%OOIP)

500

A, Ca/Na=0

40


600

50

Recovery factor (%OOIP)

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0 0

5

10

15

20

PV injected

Figure 5: Recovery and pressure drop vs. pore volume (PV) injected in LSW and LSS of the experiments A, B, C (above) and C, D, E (below). The water breakthroughs were marked on the recovery curves with the same color. Pressure drop of every experiment has the same color as the recovery curve. LSW and LSS were respectively symbolized with solid and dashed lines. The ratio of divalent to monovalent cations in the injection stream is shown in the legends. The injected LSW and LSS were the diluted in-situ brine in experiments A, B and C. In-situ brines were the same in experiments C, D and E, but the injected brines were different.


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0.14 A B C

0.12

krw

0.10 0.08

LSS

0.06

LSW

0.04 0.02 0.00 0.0

0.2

0.4 Sw

0.6

0.8

1.0

0.14 0.12

C D E

0.10

LSS

0.08 krw

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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0.06

LSW

0.04 0.02 0.00 0.0

0.2

0.4 Sw

0.6

0.8

1.0

Figure 6: End-point relative permeabilities to water at the end of LSW and LSS injection for experiments A-E. The Ca2+/Na+ ratio for experiments A and E is 0 and for B and D it is 0.0175. For experiment C, (Ca2++Mg2+)/Na+ ratio is 0.033. The injected LSW and LSS were the diluted in-situ brine in experiments A, B and C. In-situ brines were the same in experiments C, D and E, but the injected brines were different.


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(a)

IFT (mN/m)

1.E+01

SDBS in LSW-Na 1.E+00

SDBS in LSWNaCa

SDBS in LSWSFW

1.E-01 0

0.01

0.02

0.03

0.04

M2+/M+ (mol/L)/(mol/L)

(b)

1.E+01 1.E+00

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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1.E-01 1.E-02 1.E-03 0

10000 20000 30000 40000 50000 60000

NaCl concentration ( mg/L)

Figure 7: IFT of crude oil and 500mg/L SDBS at 60°C (a) in the diluted brines, (b) in NaCl brines with different salinity. M2+/M+ is the molar ratio of divalent to monovalent cations in the solutions.


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contact angle (degree)

90 75 60 45 30

A, Ca/Na=0 B, Ca/Na=0.0175 C, (Ca+Mg)/Na=0.033

15 0 Before aging After aging

After LSW

After LSS

90 contact angle (degree)

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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75 60 45

C, (Ca+Mg)/Na=0.033 D, Ca/Na=0.0175

30

E, Ca/Na=0

15 0 Before aging After aging

After LSW

After LSS

Figure 8: Contact angle of a deionized water droplet in presence of air on the silica crystals measured after different treatments. Similar to flooding experiments, LSW and LSS were the diluted aging brine in experiments A, B and C. Aging brines were the same in experiments C, D and E, but the treating brines were different. The ratio of divalent to monovalent cations in the treating brines is shown in the legends.


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30 25 20 15 10 5 0 0

0.01 0.02 0.03 M2+/M+ (mol/L)/(mol/L)

0.04

Figure 9: Equilibrium values of SDBS adsorption vs. ratio of divalent to monovalent cations (M2+/M+ ) in three packed bed experiments at 60°C; tests AE, BD and C had respectively Ca2+/Na+=0, Ca2+/Na+=0.0175, and (Ca2++Mg2+)/Na+=0.033.

200 CMC of SDBS (mg/L)

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

SDBS adsorption (mg/g)

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Ca/Na=0

160

Ca/Na=0.022

120 80 40 0 0

0.05

0.1

0.15

0.2

0.25

Ionic strength (mol/L)

Figure 10: Critical micellar concentration in solutions with different ionic strength in presence/absence of calcium cations. The perpendicular line represents the ionic strength of LSW and LSS in the coreflooding experiments.23

5. Discussion 5.1.

Low salinity water (LSW)

In this section, results of LSW flooding are discussed in terms of qualitative markers of wettability. The qualitative markers include end-point Krw at the end of LSW, water breakthrough (BT) time, post-breakthrough recovery in LSW and contact angle that was measured before and 20 ACS Paragon Plus Environment

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after the silica crystals were aged with crude oil, and after treating with LSW. In the following two sub-sections, it is attempted to compare the wettability of samples before LSW (after aging), at water BT, after BT and at the end of LSW injection. The changes are discussed in chronological order. 5.1.1. Tests A, B and C. In these tests, the aging brines contained different ratio of divalent to monovalent cations both in flooding and contact angle measurements. It can be observed from Figure 8 that, for tests A-C, the contact angles of deionized water in presence of air on the crystals increased by about 20° after aging. This large change would be an indication of wettability alteration from water- to neutral-wet during aging both in the crystals and core samples. However, wettability alteration on smooth crystals which are made of pure silica and Berea core samples with different minerals on naturally rough surfaces may have differences. Water Breakthrough (BT) time in test A was 0.41, significantly more than 0.34 and 0.33, respectively in tests B and C (Table 10). This means sample A was either initially less oil wet or its wettability modification towards more water wetness, from start of injection until BT, was more than in samples B and C. Post-breakthrough oil recovery can be another qualitative wettability marker (Figure 5). Test C reached the final LSW recovery at 1.3 PV injection as compared to 3.7 PV injection for tests A and B. This suggests that cores A and B would be more oil wet than core C. Oil recovery after BT is 10.9%OOIP in test B i.e. about three folds of that in tests A and C. An increase in oil recovery at around 3.6PV in addition to previous gradual and relatively continuous increase in recovery was observed in test B. Therefore core B seemed to be more oil wet during LSW


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flooding after breakthrough. This implication is also consistent with the estimated end-point water relative permeabilities at the end of LSW (Krw) shown in Figure 6 where Krw in test B is roughly twice as large as that in tests A and C. Figure 6 shows also that core A has become more water wet and core C has a Krw similar to A at the end of LSW flooding. The contact angle measurements, however, represent different result from the flooding experiments. Figure 8 shows that treatment of the crystal C with LSW decreased the contact angle about 10 degrees while crystals A and B showed only minor change. 5.1.2. Tests C, D and E. In these tests, the aging brines were the same (HSW-SFW) but the injected LSW brines had different ionic compositions. Since the aging brine, crude oil and preparation procedure were the same for these samples, the initial wetting conditions were expected to be the same. From Figure 8, it can be observed that the contact angles were similar for the three crystals C, D and E before aging. They were also similar after aging. Thus, the core samples after aging would have similar wettability states. Contrary to crystals A and B with no response to LSW, contact angles of crystals C, D and E after

treating

with

LSW

showed

wettability alteration

(Figure

8).

The

ratio

of

divalent/monovalent cations in LSW were 0.033 and 0.0175, and the contact angles were reduced by 11° and 16°, respectively for crystals C and D by LSW treatment. Crystal E with only NaCl in LSW had the largest contact angle reduction of 24°. This shows that crystal E became more water wet than the other two samples. Water breakthrough (BT) time was 0.33, 0.32 and 0.39 PV, respectively for experiments C, D and E (Table 10). Since the initial wettability conditions for the three samples were similar, the later BT in sample E can be attributed to the stronger wettability change towards more water wet 22 ACS Paragon Plus Environment

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by NaCl. This is consistent with the contact angle measurements. Focusing on the first 1-2 PV of LSW injection after BT showed that the duration of two phase flow was relatively similar in these tests with 3.8-4.6%OOIP increment in oil recovery (Figure 5). Cores C and D reached the ultimate LSW recovery in this period, while core E had an additional recovery after 6PV of injection where the recovery increased by 3.1%OOIP, adding up to 7.7% LSW recovery after BT. The higher recovery after BT can again be attributed to the wettability alteration characteristics of sodium chloride brine compared to the LSW brines containing divalent cations. Further, from Figure 6 it can be observed that the end-point water relative permeability (Krw) at the end of LSW flood was minimum for test E qualitatively demonstrating the wettability alteration to more water wetness by sodium chloride in LSW flooding. Flooding with diluted SFW brine containing higher amount of divalent ions, (Ca2++Mg2+)/Na+=0.033, in the case of test C led to the less wettability alteration compared to the experiments D (Ca2+/Na+=0.0175) and E (Ca2+/Na+=0). This is parallel with the contact angle measurements discussed above.

5.2.

Low salinity surfactant (LSS) – wettability, IFT and adsorption

In this section, results of LSS flooding are discussed in terms of different parameters that may indicate the wettability alteration. The qualitative markers include end-point relative permeabilities to water and contact angles that were measured before and after treatment of silica crystals by surfactant solutions. Results of IFT measurements and surfactant adsorption tests in packed bed are also discussed. As can be depicted from Table 10, the incremental oil recoveries by LSS injection were in the range of 2–6% OOIP. It seems the recovery in experiments A, B and C depends on IFT. Figure 7 shows that the IFT is lower in LSS solutions with higher divalent cation concentration. This


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results in an IFT which is one order of magnitude lower for experiments B and C than in A. On the other hand, tertiary LSS recoveries in experiments C, D and E were not consistent with the IFT measurements. This leaves the possibility of other important effects in the oil recovery. In addition, the capillary number for the experiments A, E; B, D; and C are 8.6*10-7, 4.2*10-6 and 8.6*10-6, respectively. These low capillary numbers prove that the flow was capillary dominated in all the flooding experiments. The capillary number is defined as µv/σ where µ is the viscosity of aqueous phase, v is the velocity of aqueous phase and σ is the IFT between oil and aqueous phases. IFTs are not low enough to substantially reduce the residual oil saturation in different samples. This means that the oil mobilization would be mainly due to wettability alteration. Contact angles at the end of LSW and LSS are helpful in understanding this. As illustrated in Figure 8, the changes in contact angles are considerable after LSS treatment of crystals. 45°-53° reduction in contact angle was observed in different crystals. For tests A and E, the contact angles were reduced by about 45°; for tests B-D, the contact angles were reduced by about 53°. Figure 5 shows that the incremental oil recoveries for all the tests, except test D, occurred between 2-3 PV of LSS injection followed by a marginal increment by continuing injection up to about 10 PV. In the case of test D, only 2.4% OOIP incremental oil was observed after 10 PV of LSS injection. The early oil mobilization can be attributed to the effect of lower IFT and wettability alteration. However, the minor oil mobilization in later part of LSS injection can be attributed to the wettability alteration only as there was no further increase in capillary number. In addition to the effect of calcium on the recovery curves, the wettability alteration can also be qualitatively understood from end-point relative permeabilities to water (Krw) at the end of LSS.


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Krw values of LSS in Figure 6 indicate that the core B was the least water wet among A, B and C; and core D was the least water wet among C, D and E. It seems Ca2+/Na+ ratio of 0.0175 in LSSNaCa (Table 4), made the rock less water wet than LSS with only sodium chloride (LSS-Na) and diluted in-situ brines (LSS-SFW) did. This may be an advantage as highly water wet rock would not be the optimal condition for oil recovery. Figure 6 also shows that LSS with NaCl in tests A and E has resulted in higher water wetness regardless of composition of the in-situ brine. Furthermore, difference between Krw of LSW and LSS was the smallest in test A where no divalent cations present in the aging and injection brines. A possible explanation would be the less oil wetness of sample A compared to other samples, due to absence of divalent cations in the aging brine. 5.2.1. Surfactant at high (optimal) salinity. It is difficult to differentiate between the impact of IFT reduction and wettability alteration in the oil mobilization by surfactant. The former represents mainly fluid-fluid interactions while the latter represents rock-fluid interactions. Monitoring or controlling wettability while injection would be challenging if not impossible, while changes in IFT are easier to be measured. Experiments A-E did not have ultralow IFT i.e. less than 0.01mN/m. The flooding experiment OS was designed in a way that the surfactant solution had considerably lower IFT than the LSS in experiment E. Thus the surfactant flooding was performed at high salinity at which the IFT was lower. As shown in Figure 7, solution of 500mg/L SDBS in 32500mg/L NaCl (HSW-Na) has IFT of 0.005mN/m. Therefore in experiment OS, secondary waterflooding and tertiary surfactant were performed at high salinity (HSW-Na, Table 4). The core sample was from the same Berea block from which the samples A-E were


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extracted and the same core preparation as well as the coreflooding procedure was followed. Figure 11 shows the recovery and pressure drop profiles for OS flooding experiment. The capillary number in tertiary surfactant injection of OS was 3.0*10-4, three orders of magnitude higher than in experiment E. However, the oil recovery by tertiary surfactant injection was 6.1%OOIP, similar to LSS recovery of 6.2% in experiment E. 60

500

SDBS in HSW-Na, 6.1%OOIP

water BT, 0.30PV & 41.5%OOIP

40

400

300

30 200 20

k=189mD Ø=15.1% Swirr=27.9% L=10cm D=3.8cm

10


HSW-Na, 46.3%OOIP

50 Recovery factor (%OOIP)

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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100

0

0 0

5

10 PV injected

15

20

Figure 11: Recovery and pressure drop profile of the experiment OS. Tertiary high salinity surfactant (HSS) was injected after secondary high salinity water (HSW). The IFT between surfactant solution and crude oil was 0.005mN/m. Physical properties of the core OS are given on the figure.


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0.20 E, LSW-LSS 0.15

OS, HSW-HSS

0.10 krw

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

Energy & Fuels

0.05

0.00 0.0

0.2

0.4

0.6

0.8

1.0

Sw

Figure 12: End-point relative permeabilities to water at the end of water and surfactant injections in experiments E and OS. LSW was followed by LSS in E, while high salinity water (HSW) was followed by high salinity surfactant (HSS) in OS. The injection brines contained only sodium chloride.

Similar recoveries by surfactant injection in tests E and OS suggests that rock-fluid interactions or in other words wettability alteration was stronger in low salinity surfactant that compensated for the weaker fluid-fluid interactions (high IFT of 1.6mN/m). As Figure 12 illustrates, LSS made the core more water wet than HSS. In addition it has lower residual oil saturation due to higher secondary waterflood recovery. The similar recoveries by surfactant in tests E and OS may also depend on the surfactant adsorption which is important at low surfactant concentration of 500mg/L. Due to adsorption, the effective surfactant concentration would reduce to values below critical micellar concentration (CMC), rendering the surfactant less effective. Johannessen and Spildo (2013) and Spildo et al (2014) demonstrated surfactant retention at high/optimal salinity was higher than at low salinity.18, 19 It is possible that the effective concentration of surfactant in test OS was lower than in test E due to higher retention leading to a less effective surfactant system. This means that


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surfactant flooding at low surfactant concentration would perform better in lower salinities. The effect of adsorption on the LSS tests is discussed in the next section. 5.2.2. Surfactant adsorption. Adsorption tests in packed beds revealed that surfactant adsorption was higher in presence of calcium (Figure 9). On the other hand, the critical micellar concentration (CMC) was lower at higher Ca2+/Na+ ratio. As shown in Figure 10, CMC of SDBS with NaCl solution was approximately 105mg/L, and 65mg/L at Ca2+/Na+ ratio of 0.022 as compared to 500mg/L SDBS in the flooding experiments. The lower CMC may compensate partially for the higher adsorption in presence of calcium. In all the LSS flooding experiments, the concentration of surfactant in the injection was several times higher than the CMC. As mentioned in the experimental section, values of adsorption measured in packed bed tests cannot be generalized to the amount of surfactant adsorption in core flooding experiments. Thus, it cannot be certainly determined whether the effective concentration of surfactant was below CMC or above it. Further, the effective concentration of surfactant depends also on the number of emulsified oil droplets in surfactant solution. This brings even more uncertainty in estimation of the effective concentration. Basically, as number of oil droplets increases, the effective surfactant concentration decreases and the mobilization of extra oil would be challenging. It is probably feasible to attain higher recoveries with higher surfactant concentration. However, in order to properly compare results of different flooding experiments, the concentration of SDBS was chosen 500mg/L above which at some of the diluted brines with divalent cations the precipitation was observed. Further, the surfactant formulation did not give ultralow IFT (less than 0.01mN/m) in the studied crude oil/brine/rock (COBR) system. This means that lower oil recoveries might be due to high IFT values. In a different work that we published recently24, it is


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shown reducing residual oil saturation to as low as about 10% is feasible by tertiary LSS with a different surfactant formulation and still without co-solvents, alkaline and other additive chemicals in a COBR system very similar to the one studied in this work.

6. Conclusion Effect of different Ca2+/Na+ ratios was studied in low salinity water (LSW) and low salinity surfactant (LSS) at low surfactant concentration. In the samples aged with the same in-situ brine with (Ca2++Mg2+)/Na+=0.033, LSW with only NaCl resulted in more water wet state than LSW with divalent cations. Injection of LSW with sodium ions provided highest oil recovery. The experiments on core samples aged with brines containing different Ca2+/Na+ ratio and flooded with diluted in-situ brine, it was concluded that the moderate Ca2+/Na+ ratio of 0.0175 resulted in more oil wet characteristics than the other core samples. From CMC, IFT, and adsorption experiments, it was concluded that higher Ca2+/Na+ ratio resulted in lower CMC and IFT but higher surfactant adsorption. In the core samples aged with in-situ brine containing (Ca2++Mg2+)/Na+=0.033, LSS flooding with only sodium chloride showed more water wetness with marginal higher recovery. In the experiments with core samples aged with different Ca2+/Na+ ratio and flooded with tertiary LSS prepared by dissolving surfactant in the diluted in-situ brine, the LSS with only NaCl resulted in more water wetness. At similar conditions, LSW and LSS made the core sample more water wet than HSW and HSS. At low surfactant concentration, the LSS recovered as much oil as the HSS did.


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Acknowledgments The authors would like to appreciate Lundin Norway AS, Statoil ASA, Det Norske Oljeselskap, GDF SUEZ E&P International, Unger Fabrikker AS and the Research Council of Norway for their financial support and permission to publish.

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23) Johansen, T., Investigation of Adsorption of Surfactants onto Kaolinite and Relations to Enhanced Oil Recovery Methods, Master Degree thesis, Norwegian University of Science and Technology, June 2014. 24) Khanamiri, H. H.; Nourani, M.; Tichelkamp, T.; Stensen, J.Å.; Øye, G.; Torsæter, O. Low salinity surfactant EOR with a new surfactant blend: effect of calcium cations, Energy Fuels, DOI: 10.1021/acs.energyfuels.5b02848, Jan 2016


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