Experimental Investigation of Low-Salinity Water Flooding in a Low

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Experimental Investigation of Low Salinity Water Flooding in a Low-Permeability Oil Reservoir Liang Zhang, Jiaxuan Zhang, Yi Wang, Ruohan Yang, Yu Zhang, Jianwei Gu, Mingxing Zhang, and Shaoran Ren Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03704 • Publication Date (Web): 06 Feb 2018 Downloaded from http://pubs.acs.org on February 12, 2018

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Experimental Investigation of Low Salinity Water Flooding in a Low-Permeability Oil Reservoir Liang Zhang1*, Jiaxuan Zhang1, Yi Wang1, Ruohan Yang1, Yu Zhang1, Jianwei Gu1**, Mingxing Zhang2, Shaoran Ren1 1 China University of Petroleum (East China), Qingdao, 266580, China 2 Development Center Company, Shengli Oilfield, Sinopec, Dongying, 257061, China Corresponding author: *[email protected]; **[email protected]

Abstract: Low salinity water (LSW) flooding has become a quite simple, effective and economically feasible EOR technology under the background of low oil price. The B425 block with a low permeability in Shengli oilfield China has achieved an excellent LSW flooding performance, but the main EOR mechanisms in the block are still not clear. Therefore, in order to investigate the LSW flooding mechanisms in the B425 block, a set of core-flooding experiments were conducted. The water contact angle on core slice and the zeta potential of rock particle were also measured. Then the main EOR mechanisms of LSW flooding in the block were discussed. The experimental results show that the LSW injection can indeed enhance the oil recovery in the low-permeability oil reservoir. Compared with the direct HSW (high salinity water) injection, direct LSW injection and HSW-MSW (medium salinity water)-LSW successive injection can increase the oil recovery factor by 10% and 29.52% respectively (when the core permeability is about 0.5md). The water wettability of rock can be strengthened when the LSW is injected. This can be demonstrated by the right shift of oil-water relative permeability curves, the increase of Ca2+ and Mg2+ concentrations in the produced water, and the reduction of both water contact angle and zeta potential of rock particles during core flooding or in the LSW environment. Clay particle migration was also observed during core flooding. It can be verified by the direct evidence of the produced water containing many clay particles, and the indirect evidence of the identified abnormal increase in the displacement pressure. Overall, the EOR performance of LSW flooding in the B425 block is remarkable, which has brought great confidence for the low-permeability oil reservoirs to conduct the LSW flooding in China. Key words: EOR; water wettability; ion action; weakly alkaline flooding; clay particle migration

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1 Introduction At present, water injection is still the common-used technology to produce more oil out from oil reservoirs. Compared with other EOR technologies such as chemical flooding and thermal recovery, low salinity water (LSW) flooding is a quite simple, effective and economically feasible EOR technology, which has a large potential for promotion especially under the background of low oil price [1-3]. In the past twenty years, many studies about LSW flooding have been conducted, including laboratory experiments, numerical simulation and field tests [4-17]. BP has successively conducted an LSW flooding pilot test on the northern slope of the Alaska in the North America [14], and also injected LSW into the Clair Ridge oil field in the North Sea, anticipating an increase of 420,000 barrels of crude oil. The LSW used in the Clair Ridge project is from the seawater of which the salinity is reduced to 300-2000ppm by the water purification equipment [15,16]. The second largest oilfield Greater Burgen in Kuwait also has carried out an LSW flooding, in which the water salinity is reduced from 140,000 to 5000ppm, while the production cost is only increased by $10 per barrel crude oil [17]. LSW flooding can enhance oil recovery factor by 6-20%. The main EOR mechanisms include (1) the stripping of oil film from the sand grain due to the increase of the water wettability, (2) the reduction of interface tension between oil and water because of the produced active chemicals and (3) the migration of fine particles for profile control. However, some mechanisms are still not clear due to the lack of the effective tools for direct observation, and the main EOR mechanisms of LSW flooding are often different in different oil reservoirs. Hence, more targeted investigations are needed [3,18-20]. In recent years, oil companies in China also start to pay more attention to the LSW flooding. The concept of ion-matching-water (IMW) flooding has been proposed to change the rock wettability by controlling the ion composition and the salinity of the injected water [21]. Core-flooding tests have indicated that an EOR factor of 5-15% could reach in the low-permeability oil reservoirs of Changqing and Jilin oilfields. Large-scale LSW or IMW flooding is expected to be an effective EOR method for low-permeability oil reservoirs in China. In recent years, a pilot test of LSW flooding has been conducted in the B425 block, Shengli oilfield, China. The B425 block is a beach bar sand sedimentary reservoir with a low permeability of 0.21-9.5 md. After about 8-years primary recovery process (2005-2012), water injection was scheduled for enhancing the energy of the formation. However, the B425 block 2


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is dominated by sand-shale thin interbed associated with water and oil layers sandwiching each other. It is difficult to improve the water injectivity by applying the hydraulic fracturing in such a reservoir, which can easily aggravate the vertical formation heterogeneity, and induce the injected water channeling between different layers. As a result, improving the quality of the injected water was considered. A nearby shallow aquifer connected to the Yellow River was selected as the water source which is of low salinity and weakly alkaline. The source water is treated strictly to remove the solid particles, bacteria, and oxygen before its injection into the oil reservoir. After several years of water injection (2013-2016), an excellent water flooding performance has been reached in the block using the traditional well spacing and without well hydraulic fracturing. The injected LSW is regarded as the key factor for this performance, but the specific EOR mechanisms in the block are still not clear. In order to investigate the LSW flooding mechanisms in the B425 block, a set of core-flooding experiments were conducted using different salinity water. The water contact angle of the oil droplet on the core slice and the zeta potential of rock particles in water were also measured to assist in revealing the EOR mechanisms of the LSW injection. Finally, the EOR mechanisms of LSW flooding in the B425 block were discussed.

2 Experimental section 2.1 Equipment Core flooding is the main experiment, associated with the contact angle and zeta potential tests. Core flooding experiments were conducted using the core holder flooding device. As shown in Figure 1, the device mainly consists of a fluid injection system (with an accuracy of 0.01ml/min), a core holder, a backpressure regulator, a data acquisition system (with a pressure accuracy of 0.01MPa and a temperature accuracy of 0.1oC), and an air bath for constant temperature (with an accuracy of 0.1oC). The max working pressure and temperature are 30 MPa and 150 oC, respectively. The water contact angle measurements at atmospheric pressure were performed on the KRUSS DSA100 machine, which has a working temperature between -20 and 100 oC. The zeta potentials of rock particles were tested using the Malvern Zetasizer Nano ZEN 3600 machine.

3


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Figure 1 Schematic diagram of core holder flooding experimental system

2.2 Materials The crude oil, formation water, LSW, core cores and debris used in the experiments were all sampled from the B425 block. The crude oil and formation water were separated by heating and vaporizing method. Some basic properties of the crude oil were tested, which indicated that the viscosity of the oil at the surface is 17.1 mPa.s. The oil contains 6.71wt% resin and 2.22wt% asphaltene and has an acid value of 9.07 mg KOH/g. Three kinds of water, including high salinity water (HSW), medium salinity water (HSW), and LSW were prepared for the core flooding. The compositions of these water are listed in Table 1. The separated formation water was used as the HSW which has a salinity up to 136855.5 ppm. It was also used to measure the core permeability and form the connate water in cores before core flooding. The current injected water in the block was used as LSW. It has a salinity of only 1679.2 ppm. An MSW was prepared with a salinity of 7205.8 ppm, close to the critical salinity of 5000 ppm suitable for LSW flooding recommended by Wu et al (2015) [19].

Table1 Compositions of injected water with different salinities (mg/L) -

No

Water type

pH

Cl

SO4

1

HSW

6.0

84163.6

2

MSW

7.0

3

LSW

7.5

2-

2-

Ca

Mg

2+

Salinity

47162.6

4654

564.1

136855.5

535.7

2118.3

98.7

17

7205.8

543.1

545.9

26.1

6.1

1679.2

-

+

CO3

HCO3

K +Na

0

0

311.2

4318.7

0

117.4

436.7

0

121.3

+

2+

22 real cores with a diameter of 25 mm were drilled from the full-size cores sampled from 4


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the typical wells B425 and B424 in the block. The residual fluids in these cores were washed clearly using a fast core washing device. The effective solvent of acetone recommended by the China industry standard-Core Analysis Method (SY/T 5336-2006) was used to extract the residual oil, water, and salt in the cores. It is deemed that the washing process has little effect on the core wettability and permeability. The permeabilities of these cores were measured using formation water. 12 cores with permeability between 0.05-1 md were selected for core flooding. Some uneven core ends cut from the cores were collected and used to prepare the slices and particles for contact angle and zeta potential tests. Their mineral compositions were also measured by XRD (see Table 2). The basic properties of these cores are shown in Table 3.

Table 2 Mineral compositions of sampled rock debris measured by XRD (wt%) Sampled

Sampled depth,

well

m

1

B425

2588.18

2

B425

2607.88

46

7

3

B425

2626.72

46

7

4

B424

2476.41

47

9

5

B424

2495.58

41

6

B424

2518.16

41

No

Quartz K-feldspar Plagioclase Calcite Ankerite Dolomite Clay minerals 38

10

27

9

14

-

2

33

6

3

1

4

32

8

-

3

4

28

10

-

2

4

8

29

14

-

3

5

6

25

7

18

-

3

2.3 Procedure 2.3.1 Core flooding experiment: (1) measure the length and diameter of each core; (2) measure the porosity of each core using the weighing method (the formation water was used for avoiding the damage of the saturated liquid to the core); (3) test the permeability of each core using the core holder flooding system at room condition; (4) saturate formation water and crude oil in sequence at a high pressure of 10 MPa and the reservoir temperature of 110 oC with a liquid injection rate of 0.1 ml/min. when the core is statured by crude oil, leave the core in the holder for 3-5 days to make the contact between oil, water, and rock sufficiently; (5) conduct water injection at 0.15 ml/min according to the designed scheme. During core flooding, the displacement pressure difference between the two ends of the core holder was recorded at each 15 s, while the produced oil and water were recorded at each 10 min. When each time the volume of the produced fluid reached to 10 ml (just filling up the 10 ml graduated cylinder), the concentrations of Ca2+ and Mg2+ in the produced water were titrated. 5


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When the core flooding is finished, oil recovery factor and water content in produced fluid were calculated. 2.3.2 Contact angle test: (1) put the core slice horizontally on the two slim metal cylinders in the transparent sample tank of KRUSS DSA100 machine, and pour water into the tank until the whole core slice is submerged in the water, and then heat the tank to the designed temperature (usually lower than 90 oC) through the water bath around the sample tank; (2) inject a drop of crude oil under the core slice using the injector carefully, and let the oil droplet float up and retained on the downward surface of the core slice; (3) after 30-60 min to ensure that the shape of the oil droplet on the surface of core slice has been stable, the water contact angles on the both sides of the oil droplet will be measured through the camera. 2.3.3 Zeta electric potential test: (1) grind the core debris into powder with a particle size between 10nm -25 um; (2) disperse the rock powder into the water (HSW, LSW, or MSW), and take the supernate for zeta potential test using the Malvern Zetasizer Nano ZEN 3600 machine.

2.4 Schemes According to the permeability distribution of the 12 cores, 9 runs with 3 different core permeability grades (namely 0.5 md, 0.2 md and 0.1 md) were designed for core flooding experiment (see Table 3). For each core permeability grade, three runs were scheduled respectively for HSW-MSW-LSW injection in sequence, direct LSW injection and direct MSW injection. In some runs, Ca2+ and Mg2+ contents in the produced water were measured using titration method. The mineral composition analysis, and the contact angle and zeta potential tests were regarded as assistant experiments to help the core flooding to reveal the LSW flooding mechanisms. Table 3 Experimental schemes of core flooding associated with the assistant tests Core flooding Sample Sampled No d Well Depth, m

L, cm

D, cm

K, md

φ, %

Swc, %

Injection water

Mineral compositi Contact Ca &Mg on angle titration analysis

Zeta Remarks potential

1

B425

2607.88

9.22

2.50

0.56

27.72

29

HSW-MSW-LSW

-

√

√

√

2

B424

2476.41

9.24

2.50

0.43

20.10

36

MSW

-

√

√

√

3

B425

2689.87

9.80

2.54

0.49

22.02

32

LSW

√

-

-

-

4

B425

2628.82

4.98

2.5

0.205

22.31

30

HSW-MSW-LSW

-

-

-

-

5

B425

2628.82

4.57

2.49

0.198

24.69

29

MSW

-

-

-

-

6

B424

2520.5

4.72

2.49

0.230

23.07

30

LSW

-

-

-

-

6


0.5 md grade

0.2 md grade

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7

B424

2495.58

4.92

2.51

0.111

19.85

29

HSW-MSW-LSW

√

8

B424

2495.58

4.76

2.53

0.097

25.41

33

MSW

√

9

B425

2588.18

4.92

2.53

0.129

23.06

30

LSW

√

10

B424

2518.16

-

-

-

-

-

11

B425

2626.72

-

-

-

-

-

√

√

√

√

√

√

-

√

√

√

-

-

√

√

√

-

0.1 md grade

3 Experiment results and discussion 3.1 Performance of enhanced oil recovery The experimental results of core flooding are shown in Figure 2, including the oil recovery, the water fraction of production (fw), and the displacement pressure drop (between the two ends of the core) with PV of water injected. During the HSW-MSW-LSW successive injection (no.1, 4, 7), more and more oil was produced as the salinity of the injected water decreased. This successfully proves the EOR performance of LSW injection. Accordingly, three peaks of displacement pressure drop can be observed during the successive injection of HSW, MSW, and LSW, which are corresponding to the three injection stages of water. Generally, a lower core permeability leads to a higher pressure drop for displacement. Hence, the displacement pressure drop using 0.5 md grade cores (1-2.5 MPa) is usually smaller than the case using 0.2 md grade cores (1.5-3.5 MPa), and further, the displacement pressure drop using 0.2 md grade cores is usually smaller than the case using 0.1 md grade cores (4-14 MPa). However, an abnormally high-pressure drop up to 8-16MPa was observed in the run of no.3, which is much larger than the pressure drops of displacement in the runs of no.1 and 2 using the similar core permeability (0.5 md grade). The reason for this large pressure drop may be due to the blockage of the core by the moving clay particles. In addition, for the water cut fw, it usually rose to 60-90% quickly once the injected water breakthrough and then fluctuated during core flooding until it reached to 100%.

100

1.5

60

1.0

40 ∆P Rf fw

0.5

20

2.0

Pressure drop, MPa

80

oil recovery factor / fw, %

2.0

MSW

80

60

1.0

40 ∆P Rf

20

fw 0.0

0 0

1

2 3 4 5 Pore volume injected, PV

6

7

0.0

0 0

1


6

100

16

1.5

0.5

18

No.2

7

7


No.3 80

14

LSW

12 60 10 8 40 6

∆P

4

fw

2

Rf

20

0

0 0

1

2 3 4 Pore volume injected, PV

5

6

Oil recovery factor / fw, %

2.5

Pressure drop, MPa

100

No.1


2.5

Pressure drop, MPa

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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Energy & Fuels

60

2.0 40 1.5 1.0

20 MSW 0 2

4

40 1.5 1.0

20

0.5

0.0 0


14

0.0 0

2

10

60

8

LSW 40

6 ∆P HSW

MSW

2

20

Rf fw

0

0 0

5


25

Pressure drop, MPa

80


No.7

MSW

40 1.5

∆P

1.0

fw

0.5

Rf

80

60

40

6

∆P

4

Rf

2

fw

20

4

6

8

10

100 LSW

0 12

No.9 80

12 10

60

8 40

6 ∆P 4

Rf

20

fw

2

0

20

0 2

14

8


2.0

16

No.8

10

2

60 2.5

Pore volume injected, PV

12

0

3.0

0

100

14

80

3.5

12

16

100

14 12


No.6

LSW

0.0

0

16

16

4

60

2.0

Pressure drop, MPa

HSW

fw 2.5


0.5

Rf

3.0

100

4.0 80

∆P

3.5

4.5

No.5


LSW

fw

2.5

100 MSW

0


∆P Rf

3.0

Pressure, MPa

3.5


Pressure drop, MPa

4.5 4.0

80

Pressure drop, MPa

100

No.4

4.0


4.5

Pressure drop, MPa

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 0

2


10

12

Figure 2 Experimental results of core flooding in different runs

The comparison of oil recovery in different core-flooding runs is shown in Figure 3. The final oil recovery factors under different displacement conditions are listed in Table 4. Taking the core-flooding results of runs using 0.5 md grade cores for example, it can be seen that the final oil recovery factor of direct LSW injection can be 46.86%, 10.67% higher than the 36.19% of direct HSW injection. When the HSW, MSW, and LSW are injected in succession, the final oil recovery factor can be up to 65.71%, 29.52% larger than the direct HSW injection. Comparing the direct LSW injection and the HSW-MSW-LSW successive injection, continuous injection with water salinity decrease can reach an oil recovery factor 18.85% higher than the direct LSW injection. The experimental results of core flooding using cores with 0.2 md and 0.1 md grades also indicate the similar conclusions. Overall, the final oil recovery factors of different runs can be ranked in an order of HSW-MSW-LSW > LSW > MSW>HSW (see Figure 4a). Therefore, from the point of view of the largest oil recovery, HSW-MSW-LSW continuous injection is the best choice but a large PV number of water should be injected. Comparatively, direct LSW injection is ideal, which can achieve a good flooding performance in a short time using a small PV number of water injection.

8


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100

60

LSW

40

MSW

HSW

20 0

HSW-MSW-LSW-No.4 MSW-No.5 LSW-No.6

80 60

Oil recovery factor, %

80

100

100




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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LSW

40

MSW HSW

20


8

60 LSW MSW

40 HSW

20 0

0

0


80

0


20

0

10 20 Pore volume injected, PV

30

Figure 3 Comparison of oil recovery in different core-flooding runs Table 4 Final oil recovery factors under different displacement conditions No

Permeability grade, md

Injection type

HSW, %

MSW, %

LSW, %

1

0.5

direct injection

36.19

44.35

46.86

2

0.5

successive injection

36.19

56.19

65.71

3

0.2

direct injection

42.97

47.22

52.87

4

0.2


42.97

50.90

63.35

5

0.1

direct injection

39.72

52.63

59.57

6

0.1


39.72

53.74

67.76

As shown in Figure 4a, the EOR performance of LSW is sensitive to the core permeability in spite of the small range of permeability varying from 0.1 md to 0.5 md. In the cases of direct LSW and MSW injections, as the core permeability increases, the final oil recovery factor decreases by 12.71% from 59.57% to 46.86%, and by 8.28 % from 52.63% to 44.35%, respectively. It is probably related to the pore size and the boundary layer of fluid in the pore. In the low-permeability reservoir with oil or intermediate wettability, the crude oil in pore can be divided into two parts. The first part is the oils adsorbed on the lipophilic pore wall, which cannot flow and forms the boundary layer. The second part is the oils outside the boundary layer, which can flow in the middle channel of the pore. In general, the smaller the core permeability, the smaller the pore size, and the greater the proportion of the boundary layer thickness occupying the pore size. In this case, most of the crude oil remains in the boundary layer, but fortunately, the EOR mechanisms of LSW/MSW happen to target the immobile oil in the boundary layer. Therefore, for the cores with a lower permeability, LSW/MSW injection can achieve a higher recovery factor, while the cores with a higher permeability reach a relatively smaller oil recovery factor. Comparatively, in the cases of direct HSW injection and successive injection of HSW, MSW, and LSW, the effect of permeability on the final oil 9


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recovery factor is weaker. The reasons for these two cases are different. For the direct HSW injection, the salinity of injected water is the same as the formation water. Hence, the EOR mechanism of LSW based on the change of water salinity is very weak and has a little effect on the boundary layer of oil in the pore. On the contrary, the successive injection of HSW-MSW-LSW can cause full interactions between the water, crude oil, and clay minerals because of the gradual decrease in salinity and the long time and large volume of water injection. The EOR mechanisms of LSW can play a full effect on the oil boundary layer to strip most of the immobile oil from the pore wall. Hence, the final oil recovery factors are relatively higher and close in the runs of no.1, 4, and 7 (between 63.35%-67.76%). The influence of salinity of injected water on EOR performance has shown in Figure 4b. It can be seen that when the salinity of injected water decreases smaller than 7206 ppm, the oil recovery factor turns to increase sharply not only in the case of direct water injection but also in the case of successive injection. Hence, a potential critical salinity around 7206 ppm may exist. When the salinity of injected water is lower than the critical value, the EOR mechanisms of LSW will become remarkable. However, this study only tested three salinities, more salinities should be examined to determine the exact critical salinity.

80

70

70

60

35 HSW-MSW-LSW successive injection

HSW/MSW/LSW direct injection

60 50 40 30

HSW-MSW-LSW LSW MSW HSW

20 10

30 Enhanced oil recovery, %


Final oil recovery factor, %

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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50 40 30 0.1md grade

20

0.2md grade

10

0.5md grade

0

0 0

0.1

0.2 0.3 0.4 Permeability, md

0.5

0.6

25 20

0.1md grade 0.2md grade 0.5md grade

15 10 5 0

0

50000 100000 Salinity, ppm

a. Influence of permeability

150000

0

50000 100000 Salinity, ppm

150000

b. Influence of salinity

Figure 4 Influences of core permeability and salinity of injected water on the EOR performance

3.2 Characteristics of relative permeability curves According to the core flooding data, the oil-water relative permeability curves of the runs of no.1, 4 and 7 have been determined through a simple method. The oil-water relative permeability curves can be calculated in term of the following empirical equations (1) [22] if the parameters krwro, krorw, Sor, Swc, n, and m are known. The parameters n and m are mainly 10


Page 11 of 24

related to the pore characteristics of rock, which decide the shape of the relative permeability curves. For simplicity, these two parameters were determined by fitting the previous oil-water relative permeability curves from the same block, while the other parameters were determined using the core-flooding data in this study. As seen in Figure 5, the parameters n and m were fitted to be 2.35 and 1.65, respectively. The other parameters are listed in Table 5. Then, the oil-water relative permeability curves of HSW-MSW-LSW successive injection were calculated, as shown in Figure 6.

k = k

, k = k

(1)

where krw and kro are the relative permeabilities of water phase and oil phase, respectively, fraction; Swc and Sor are the connate water saturation and the residual oil saturation, respectively, fraction; Sw is the water saturation, fraction; krwro is the maximum krw at Sor, fraction; krocw is the maximum kro at Swc, fraction; n and m are shape indexes for water and oil relative permeability curves, respectively. 1.0 kro krw kro-fitted krw-fitted

0.8 0.6 kr

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

0.4 0.2 0.0 0.0

0.2

0.4

0.6

0.8

1.0

Sw

Figure 5 Fitting result of the previous oil-water relative permeability curves from the B425 block

Table 5 Parameters for the calculation of oil-water relative permeability curves Run

Injection stage

krocw

krwro

Swc

Sor

1

HSW

0.92

0.22

0.29

0.53

1

MSW

0.92

0.25

0.29

0.37

1

LSW

0.92

0.26

0.29

0.29

4

HSW

0.50

0.23

0.31

0.46

4

MSW

0.50

0.19

0.31

0.40

4

LSW

0.50

0.17

0.31

0.30

7

HSW

0.30

0.056

0.29

0.53

7

MSW

0.30

0.061

0.29

0.40

11


Energy & Fuels

7

LSW

0.30

0.056

0.29

0.29

o

Note: at 110 C and 10 MPa, the viscosity of crude oil is uo=1.20 mPa.s, the viscosity of water is uw=0.26 mPa.s 1.0

1.0

0.6

0.8

krw-HSW

kro-HSW

krw-MSW

kro-MSW

krw-LSW

kro-LSW

No.4 0.8

0.6

kro-LSW

0.4

0.4

0.2

0.2

0.2

0.0

0.0

0.2

0.4

0.6

0.8

1.0

kro-HSW

krw-MSW

kro-MSW

krw-LSW

kro-LSW

No.7

0.6

0.4

0.0

krw-HSW

kr

0.8

1.0

No.1

kr

krw-HSW kro-HSW krw-MSW kro-MSW krw-LSW

kr

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

Page 12 of 24

0.0

0.0

0.2

0.4

0.6

0.8

1.0

Sw

Sw

0.0

0.2

0.4

0.6

0.8

1.0

Sw

Figure 6 Oil-water relative permeability curves calculated based on the runs of no1, 4 and 7

According to the calculated oil-water relative permeability curves, as shown in Figure 6, it can be seen that as the salinity of injected water decreases, the relative permeability (kr) curves are stretched to the right along with the decrease of Sor. The water wettability of the core become stronger and stronger. During the HSW injection stage, the wettability of the core can be judged to be oleophilic or intermediate-philic according to the Sw lower than 0.5 or close to 0.5 at the equal kr point of water and oil phases. When the injected water is changed to MSW and LSW subsequently, the Sw at the equal kr point increases larger than 0.5. The wettability of the core alters to be hydrophilic. In addition, the kr curves can also reflect the blockage behavior of particles in the core, which will be discussed in detail in the next section. Overall, small core permeability usually causes small oil-water kr. The region occupied by kr curves will become flat as the core permeability decreases.

3.3 Particle migration and blockage Obvious clay particle migration was observed during core flooding. Figure 7a shows the situation of the produced water in the run of no.1. As the salinity of injected water decreased, more and more clay particles were produced out. The same phenomenon was also observed in other runs. Besides, clay deposition was also found in the formation water sampled from the wellhead in the field. It can well support the observation during the core flooding (Figure 7b). Particle migration can increase or decrease the absolute permeability of the core. If we assume that the absolute permeability of core does not change, the damage to fluid flow induced by particle migration can be characterized by the kr. Hence, when the particle 12


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Energy & Fuels

migrates within the core and causes the blockage of pores, the krwro will be reduced (see no.4 in Figure 6). When the particles migrate out of the core, large pore path and high absolute permeability may be generated. In this case, the krwro will increase (see no.1 in Figure 6).

a. Status of produced water in the run of no.1 b. Clay particles produced from the block Figure 7 Clay particles produced during core flooding and in the field

Based on the calculated kr curves in Figure 6, the theoretical pressure drops of displacement at different Sw in cores were calculated using the equation (2). As shown in Figure 8, in theory, a typical displacement pressure drop during a water injection stage should increase first and then decrease. The peaks of pressure drop during HSW, MSW and LSW injection stages should decrease in sequence. Comparing the real pressure drops with the theoretical ones, it can be seen that the overall fluctuations of displacement pressure drop in the runs of no. 1, 4, 7 are in accordance with the theoretical trends, but the abnormal change of the pressure drop during core flooding can also be further identified. Taking the run of no.1 for example, an abnormally high-pressure peak of 2 MPa occurred during the MSW injection stage, while the peaks of pressure drop during the previous HSW injection stage and the subsequent LSW injection stage were smaller (see no.1 in Figure 2). This is very different from the theoretical results which indicate that the largest peak of pressure drop should appear during the HSW injection, and the peak during MSW injection should be only 1.5 MPa (smaller than the real peak of 2 MPa) (see no.1 in Figure 8). Combing with the observation on the produced water, the phenomenon of abnormal pressure peak can reflect the particle migration and temporary blockage in the core during water flooding. Hence, we think that the whole trend of displacement pressure drop in the core is decided by the total mobility of oil and water phases, while the local fluctuation of pressure drop is tightly related to the particle migration and temporary blockage in the pore.

∆ = /

10#

(2)

where ∆P is the theoretical pressure drop of displacement, MPa; Q is the water injection rate, 13


Energy & Fuels

ml/s; L is the length of core, cm; K is the absolute permeability, md; A is the cross area of core, cm2; kro and krw are the relative permeabilities of oil and water phases, respectively, fraction; μo and μw are the viscosities of oil and water, respectively, mPa.s. 5

1.5

1.0

HSW MSW LSW

0.5

0.0

20

No.4

Pressure drop calculated, MPa

No.1

Pressure drop calculated, MPa

2.0 Pressure dorp calculated, MPa

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

Page 14 of 24

4 3 HSW

2

MSW LSW

1 0

0.28

0.38

0.48

0.58

0.68

0.78

No.7 16 12 HSW

8

MSW

4

LSW

0

0.3

0.4

0.5

0.6

0.7

0.8

Sw

Sw

0.3

0.4

0.5

Sw

0.6

0.7

0.8

Figure 8 Theoretical pressure drops of displacement at different Sw during core flooding

3.4 Ion concentration change in produced water The Ca2+ and Mg2+ concentrations in the produced water and the pH of the produced water in the runs using 0.1 md grade cores are shown in Figure 9. It can be seen that in the run of no. 7, as the salinity of injected water deceased, the Ca2+ and Mg2+ concentrations in the produced water decreased, while the pH of produced water increased. Gradually, the properties of the produced water became close to the injected water. During the HSW injection stage, a temporary decrease of Ca2+ concentration in the produced water occurred possibly due to the Ca2+ adsorbed to the polar substances in the crude oil (the crude oil has been desalted partly during oil and water separation for core flooding). When the MSW was injected directly in the run of no. 8, the Ca2+ and Mg2+ concentrations and the water pH fluctuated with injected water PV. When the LSW was injected directly in the run of no. 9, weak peaks of Ca2+ and Mg2+ concentrations and pH in the produced water were observed, which can reflect the ion action of LSW in the core. The dilution effect of injected LSW can weaken the bridging interaction of the divalent positive ions and their formed diffuse double layers between the pore wall and the oil components with negative polarity. The ion exchange for oil components with positive polarity can also occur on the pore surface. In this case, many Ca2+ and Mg2+ ions will be released from the surface of the pore into the water, leading to the change of the rock wettability. More and more crude oil adsorbed on the pore surface in the boundary layer will be stripped away from the pore wall.

14


4000

8

140

7

120

7

100

6

6 MSW

3000 HSW

2000

LSW

5

Ca2+

4

Mg2+

3

pH

2

1000

1 0

0 0

5


30

8

No.8

MSW

5

80

4 60

Ca2+

40

Mg2+

3 2

pH

20

1

0

0 0

3


15

140

8

No.9

LSW

pH Ion concentration, mg/L

No.7

pH Ion concentration, mg/L

5000

Ion concentration, 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

Energy & Fuels

120

7

100

6 5

80

Ca2+ Mg2+ pH

60

4

pH

Page 15 of 24

3

40

2

20

1

0

0 0


12

Figure 9 Ca2+ and Mg2+ concentrations in the produced water in the runs using 0.1md grade cores

3.5 Change of water contact angle The tested contact angle of water on the both sides of the oil droplet on the core slice are shown in Table 6. When the salinity was changed, about 0.5-1 hour was required for the contact angle to reach stable. It can be seen that when the HSW is changed to LSW, the contact angle of water usually becomes smaller, which indicates that the water wettability of the core slice becomes stronger. Under the atmospheric condition with a crude oil-kerosene volume ratio of 1:1, the largest reduction of the water contact angle is up to 35o (see no. 4). Some core slices presented a weak response (see no. 3 and 6), while some core slices gave a very different reduction of contact angle on the both sides of the oil droplet (no. 1). The main reason for these phenomena is the uneven wettability of the rock surface due to the uneven distribution of minerals, especially the clay minerals on the rock surface. It should be noted that the location of the oil droplet on the core slice in the LSW environment might be not the same location of the oil droplet on the core slice in the HSW environment. This factor may increase the contact angle variation due to the change of salinity (Table 6 left and Figure 10). When the testing temperature was increased to 40 oC and the crude oil was used, the contact angle reduction of water can still be observed in the test, but the reduction becomes smaller. The largest reduction of the contact angle is only 9.6o (see no. 4). It indicates that increased temperature is not beneficial to achieving a remarkable reduction of contact angle (see Table 6 right). At the same condition, a dynamic contact angle test was further conducted, which can preclude the influence of the oil droplet location on the measurement of the contact angle reduction. As more and more LSW was added into HSW, the continuous reduction of the contact angle of the same oil droplet can be observed. As seen in Table 7, when the equal volume of LSW was mixed with the HSW, the contact angle of water reached the greatest 15


Energy & Fuels 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

Page 16 of 24

reduction. A decrease of water contact angle of 7.24o was achieved on the right side of the oil droplet on the no. 4 core slice.

a. No. 2: B425-2607.88 (left: HSW; right: LSW) b. No. 4. B424-2476.41(left: HSW; right: LSW) Figure 10 Reduction of water contact angle when HSW is changed to LSW (Crude oil: kerosene =1:1, 20 oC, 1atm) Table 6 Static contact angles of water tested under different conditions Crude oil: kerosene =1:1, 20 oC, 1atm

Condition

No

Core slice

HSW

LSW

Crude oil, 40 oC, 1atm

Reduction angle, °

HSW

LSW

Angle reduction, °

Left

Right

Left

Right

Left

Right

Left

Right

Left

Right

Left

Right

22.76

28.40

10.43

0.86

31.96

31.26

27.06

28.84

4.90

2.42

1

B425-2588.16

33.19

29.26

2

B425-2607.88 46.43

46.03

31.67

30.87

14.76

15.16

26.54

27.29

26.30

24.63

0.24

2.66

3

B425-2626.72 37.97

37.32

37.95

38.05

0.02

-0.73

30.41

31.09

28.34

26.45

2.07

4.64

4

B424-2476.41 66.61

66.32

31.13

30.83

35.48

35.49

34.60

33.70

25.60

24.10

9.00

9.60

5

B424-2495.58 48.37

48.67

40.08

40.09

8.29

8.58

26.77

26.63

25.75

26.50

1.02

0.13

6

B424-2518.16

30.15

30.29

30.45

-0.20

-0.30

33.44

32.54

25.89

25.53

7.55

7.01

30.09

Table 7 Dynamic contact angle of water tested under 40 oC, 1atm (crude oil) No

Core slice

HSW

HSW:LSW=4:1 HSW:LSW=4:2 HSW:LSW=4:3 HSW:LSW=4:4

Angle reduction,

o

Left

Right

Left

Right

Left

Right

Left

Right

Left

Right

Left

Right

2

B425-2607.88 30.55

29.57

28.97

29.33

27.38

28.01

28.25

27.78

26.63

25.84

3.92

3.73

4

B424-2476.41 30.36

35.16

27.69

33.53

27.15

32.52

28.07

28.68

28.49

27.92

1.87

7.24

6

B424-2518.16

31.05

30.18

30.22

30.15

30.47

29.48

29.61

29.39

30.63

2.34

0.42

31.73

Overall, different core slices with different mineral compositions present different contact angle changes. In most cases, the contact angle of water can reduce by 5.64-35.49° when HSW is changed to LSW. The LSW is beneficial for improving the water wettability of core as well as striping the residual oil from the pore wall. However, the correlation between the contact angle and the clay content of core slice is not tight (Figure 11).

16


Page 17 of 24

40

Contact angle reduction, °

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

test I 30

test II test III

20 10 0 0

1

2 3 4 Clay content, wt%

5

6

Figure 11 Correlation between the contact angle reduction of water and the clay content of core (Test I: static test, crude oil: kerosene =1: 1, at atmospheric conditions; Test II: static test, crude oil, under 40 oC, 1atm; Test III: dynamic test, crude oil, under 40 oC, 1atm)

3.6 Change of zeta potential The preliminary zeta potential tests of rock particles show that the correlation between the salinity of the injected water and the zeta potential of rock particle is weak or none. The repeated test also indicated the conclusion. Hence, in order to further identify the reasons, different solid particles (including the real core particles, clay minerals, and nano-SiO2 particles) and different water (including HSW, LSW, and three kinds of NaCl brines with different salinities and Ca2+ concentrations) were tested for comparison. The experimental results are shown in Table 8 and Figure 12. The results show that there is a good correlation between the zeta potential and the water salinity when the clay particles and nano-SiO2 were used. It can be seen that with the decrease of the salinity, the zeta potential of the particles gradually decreased, indicating that more and more divalent cations depart from the surface of the particles. These results are corresponding to the studies of Shehata et al[12]. However, the zeta potential of the real core particles is somewhat less correlated with the salinity. It is believed that this may be due to the inhomogeneous mineral composition of the core particles and the uneven zeta potential distribution on the particle surface (see Figure 12b). In practical, only limited particles were randomly selected by the machine from the dispersion for zeta potential measurement. Hence, the results have a certain randomness and even no obvious law at all. However, it is no doubt that the zeta potential of the clay part of the core particles would be reduced as the degree of salinity decreases.

Table 8 Test results of the zeta potentials of different particles (unit: mv) 17


Energy & Fuels

Water

True core

HSW LSW 2+

80000 ppm NaCL(2000ppm Ca ) 2+

40000 ppmNaCL(1000ppm Ca ) 2+

20000 ppmNaCL(500ppm Ca )

Pure clay

Nano SiO2

-35.77

-37.32

-16.67

-37.81

-38.59

-43.18

-5.60

-4.26

4.06

1.48

-8.89

2.73

-8.00

-16.64

-3.43

10 0 Zeta potential, mv

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

Page 18 of 24

-10 -20 Rock particle Clay particle Nano SiO2 particle

-30 -40 -50 HSW

LSW

80000ppm 40000ppm 20000ppm NaCl(2000ppm NaCl(1000ppm NaCl(500ppm Ca) Ca) Ca)

a. Zeta potentials of different particles

b. Heterogeneous clay distribution on core grain

Figure 12 Zeta potentials of different particles in different water 3.7 EOR mechanisms of LSW flooding in B425 block 3.7.1 The applicability of reservoir conditions of B425 block The reservoir conditions of the B425 block have been compared with the reservoir screening criteria for LSW flooding, as shown in Table 9. These screening criteria are proposed by Wu et al (2015) [19]. It can be seen that the reservoir conditions of B425 block can meet the criteria very well: (1) the target reservoir has a high formation water salinity, in which the contents of Ca2+ and Mg2+ are also high; (2) the salinity of the injected LSW is only 1679 ppm within the recommended best range of 1000-2000 mg/L; (3) the relative permeability of water phase is high, and the water and salt sensitivities are weak or none in the reservoir; (4) the reservoir temperature is not too high, just slightly higher than the recommended upper limit; (5) the previous test indicated that the typical clay content in B425 block is 10.3wt% in average (the clay content of core used in this study is only 2wt%-5wt%, but the EOR performance of LSW flooding is still outstanding); (6) the total content of dolomite and calcite in the reservoir is high up to 23.4wt%; (7) the crude oil contains polar substances, and its acid value is high.

Table 9 Reservoir conditions of B425 block compared with the reservoir screening criteria for LSW flooding 18


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Energy & Fuels

No.

1

2

3

4

5

6

7

Screening criteria[19] Formation water. There must be formation water in the reservoir. The EOR potential is related to the original formation water saturation. The formation water should contain divalent cations of Ca2+ and Mg2+, which are necessary for ion exchange, bridging and diffusion effects. LSW suitable for injection. LSW is very sensitive to ion composition, especially to the Ca2+ and Na+. The water salinity recommended is 1000-5000 mg/L. The best EOR performance can be reached when the salinity is between 1000-2000 mg/L. Too high salinity cannot guarantee a good EOR effect, while too low salinity will lead to serious clay expansion. The plug of pore throat will cause water and oil production drop. Water relative permeability. When LSW is injected, due to the particle migration or miscible effect between oil and water, the water injection pressure will increase, and the water relative permeability will decrease. Hence, good water relative permeability can keep good water injectivity. Reservoir temperature. The reservoir temperature for LSW flooding is usually lower than 100 oC

Clay minerals. They are the essential condition for particle migration, ion exchange, cationic bridging, and diffuse electric double layer, which has the significant influence on EOR performance.

Carbonate minerals. The rock contains carbonate crystals or carbonates. Carbonate dissolution can enhance the pH of water, promoting the desorption of oil from the surface of the rock, and improving the water wash efficiency. The polar functional group in crude oil. The crude oil must contain the polar functional group. It is the basis for ion exchange, cationic bridging, and diffuse electric double layer.

Reservoir conditions of B425 block The irreducible water of the block is about 35%; the original salinity is 127568-169471ppm with an average of 136855.5ppm, Ca2+ of 4654ppm, Mg2+ of 564.1ppm. The original pH is 6.0.

Remarks High salinity with high Ca2+ and Mg2+ concentrations

The injected LSW salinity is 1679.2ppm with a weakly alkaline pH of 7.5 and Ca2+ of 26.1ppm, Mg2+ of 6.1 ppm.

LSW salinity within the recommended range

According to the tested oil-water kr, the maximum krw is 0.2-0.6; the water and salt sensitivities of rock are weak or none

Medium to high water relative permeability

A Little higher The temperature of the B425 block than the upper o is 102-121 C. limit The clay content of the block is between 2wt%-5wt% with an average of 4wt%. Previous tests indicated the clay content in a High clay range of 5.7wt%-12.8wt% with an mineral average of 10.3wt%, of which illite content takes 30wt%, illite/smectite takes 33wt%, kaolinite takes 19.8wt%, chlorite takes 15.1wt%, chlorite/smectite takes 2.1wt%. The block contains 6.5wt%-13.7wt% of calcite with an High average of 11.9wt% and carbonate 4.0wt%-24.9wt% of dolomite with content an average of 11.5wt% The resin and asphaltene contents are 6.71wt% and 2.22wt% High acid respectively. The acid valve is 9.07 valve mg KOH/g

3.7.2 The main EOR mechanisms of LSW flooding in B425 block Based on the above experimental results, the EOR mechanisms of LSW injection in the B425 block, including the water wettability increase and the clay particle migration are explicit. The evidences for the former include the reduction of the water contact angle, the increase of the concentration of Mg2+ and Ca2+ in the produced water, the right shift of oil-water kr curves, 19


Energy & Fuels 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

and the decrease of the zeta potential of clay particles in the LSW environment. The evidences for the latter include the clay deposition in the produced water both in the field and during the core flooding, the change of krwro, and the abnormal fluctuation of the pressure drop in the core flooding. In addition, the mechanism of IFT (interface tension) decrease may occur in the reservoir because of the weakly alkaline pH of the LSW, which may lead to a weakly alkaline flooding. For the dramatical migration of clay particle observed in the core flooding, there are two points which should be paid more attention to. The first one is the content of clay in the reservoir. When LSW is injected into the oil reservoir, clay particle migration may lead to three different results. The first case is to induce the temporary blockage of the pore, which can play the effect of profile control for displacement. The second case is to cause the high-permeability path in the oil reservoir, which is conducive to decreasing the injection pressure of water but may induce the water channeling in the production wells. The last case is to cause the total blockage of the pore due to the serious clay expansion. Therefore, there should be a critical content for the clay in the oil reservoir, which can ensure the LSW injection to achieve a good injectivity and a good profile control in the case of clay particle migration. The second point that should be noticed is the salinity of the LSW. The salinity of the LSW should match with the content of the clay in the oil reservoir. Hence, according to the critical clay content, there should be a critical salinity of LSW. If the salinity of water is too high, the EOR performance is hard to be guaranteed. If the salinity of water is too low, clay expansion may be out of control and induce a significant decrease in the water injectivity. Hence, it is necessary to understand the relationship between the clay content and the salinity of LSW comprehensively, which deserves further studies in the future. In the B425 block, direct LSW injection has been applied since 2013 after the block was produced only by natural energy for 8 years (from 2005 to 2012) (the primary oil recovery factor is about 5.5%). Although HSW-MSW-LSW successive injection can reach the highest oil recovery factor, it lasts a long time, and its economy may be not the best. Comparatively, direct LSW injection is more attractive, which can reach a high recovery factor in a short period. Hence, finally, the field operator decided to inject LSW directly. In order to guarantee the high quality of the LSW, many measures have been taken in the field, including the ultrafiltration membrane to keep the solid particle size in LSW smaller than 0.005-0.10 μm as well as the oxygen isolation membrane to keep the weak alkaline pH of the LSW. Because of 20


Page 20 of 24

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Energy & Fuels

the high quality of the injected LSW, a good flooding performance has been achieved in the B425 block with a well spacing of 210-280 m and no hydraulic fracturing. Early in the LSW injection, there were only two wells for water injection with an injection-production ratio of 1.4. As the pressure of the block was restored, 8 months later in August 2013, the daily liquid, daily oil, and water fraction started to increase (liquid rate increased from 38.8m3/d to 47.5m3/d, oil rate increased from 30.1m3/d to 35.8m3/d, and water fraction increased from 22.4% to 24.5%). Subsequently, more water injectors were put into operation, and the injection-production ratio was improved to 2.1-3.1. After April 2014, an obvious increase in daily liquid and daily oil and a little decrease in water fraction were initiated under the effect of the EOR mechanisms of LSW (liquid rate increased to 85.6-105.8 m3/d, oil rate increased to 62.9-78.5 m3/d, and water fraction increased to 26.6% then decreased to 25.8% ). Combined the lab experiments with the field application, we think the responding time for LSW flooding in the field test mainly depends on the recovery time of the formation pressure and the seepage velocity of the injected water in the reservoir. Overall, after three-year LSW flooding, the production performance of the B425 block has been significantly improved (Figure 13). The EOR factor of LSW flooding in B425 block is predicted to be 19.3%.

Figure 13 Production performance of LSW flooding in 10 well groups in the B425 block

4 Conclusions (1) The core-flooding experiments can successfully prove the EOR potential of LSW injection in the low-permeability oil reservoirs. Compared with the direct HSW injection, the 21


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direct LSW injection and the HSW-MSW-LSW successive injection can enhance the final oil recovery factors by 10.67% and 29.52%, respectively (in the case of 0.5md grade cores). Successive injection is beneficial to the sufficient interaction between the water, oil, and rock for reaching a higher oil recovery factor. The low core permeability and the water salinity less than 7206 ppm are more conducive to playing the EOR mechanisms of LSW in the oil reservoir. (2) The water wettability of the core can be enhanced with the decrease of the salinity of the injected water. It can be proved by the right shift of the oil-water kr curves, and the increase of the concentration of Ca2+ and Mg2+ in the produced water during core flooding. This recognition is also supported by the reduction of the water contact angle and the decrease of the zeta potential of clay particles in the LSW environment. The specific reason causing the water wettability of rock increase is mainly due to the dilution effect on the diffuse electric double layer and the ion exchange between oil, water, and rock. (3) Clay particle migration was observed during core flooding. As the salinity of injected water decreased, more and more clay particles were produced out. The increase or damage of the core permeability induced by the particle migration can be characterized using krwro. The overall change trend of displacement pressure drop during core flooding is controlled by the total mobility of oil and water (kro/μo+krw/μw). The abnormal increase of pressure drop caused by temporary blockage of particles can be identified by comparing the real pressure drop of displacement with the calculated theoretical data based on the oil-water kr curves. (4) The B425 block is a typical oil reservoir suitable for LSW flooding. Based on the investigation of the lab experiments and the field application, the main EOR mechanisms of LSW flooding in the block are the increase of the water wettability and the migration of clay particles. A weakly alkaline flooding may exist. Overall, the EOR performance of LSW flooding in the B425 block is remarkable, which has brought great confidence for the low-permeability oil reservoirs to conduct the LSW flooding in China.

Acknowledgements This research is supported by the company of Shengli oilfield (30203573-16-zc0613-0021), and also partly supported by the Fundamental Research Funds for the Central Universities (No. 15CX 05036A) and the National Major S&T Project (No. 2016ZX05056004-003). We are grateful to Ph.D Guodong Cui, masters Shufeng Pei, and Shuaijie Su for their selfless helps to 22


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ensure the well running of the experiments. We also appreciate the reviewers and editors for their constructive comments to make the paper high quality.

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Experimental Investigation of Low-Salinity Water Flooding in a Low

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