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THE IMPACT OF FRESH WATER INJECTION ON HEAVY OIL

DISPLACEMENT FROM SANDSTONE RESERVOIRS

Ilyas K. Turgazinov, Iskander Sh. Gussenov and Birzhan Zh. Zhappasbayev

Kazakh National Research Technical University named after K.I.Satpayev, Almaty, Kazakhstan

E-Mail: ilyasrgu15@gmail.com

ABSTRACT

In recent years, numerous studies have confirmed that in certain conditions, low salinity water flooding (LSW)

may be more effective than high salinity water flooding (HSW) both in carbonate and sandstone reservoirs. The available

data suggests that depending on reservoir conditions, a number of phenomena may be responsible for incremental oil

recovery (IOR) during LSW. Wettability alteration, clay swelling, an increase in pH, multi-ion exchange, double layer

expansion and fine migration were claimed to be the underlining mechanisms for an increase in oil recovery during LSWF.

However, due to a large number of interrelated variables, the ranges of reservoir conditions in which each of these

mechanisms is activated has not yet been identified. Thus, additional research is required for a better understanding of the

principles and limits of LSWF. However, only a few studies have been conducted on heavy oil displacement. In this paper

the higher salinity contrast between injections of reservoir brine followed by injection of fresh water into the cores were

tested to define the impact of injecting water salinity on the heavy oil recovery factor. Such extreme salinity contrast of

injecting water was used to demonstrate the effect of low salinity water flooding in laboratory experiments and to check the

possibility of using low salinity water flooding as an EOR method.As a result, fresh water resulted in 19% of IOR after

initial HSW in the preferentially oil-wet sand pack, whereas incremental recovery in the hydrophilic sand totaled only

around 4%. In addition, the data collected on the injection pressure change coupled with the analysis of rock mineralogy

and the effluent samples suggests that fine migration takes place during the injection of fresh water.

Keywords: low salinity water flooding, wettability alteration, fines migration, oil production, porous media, viscous oil.

INTRODUCTION Water injection is the most popular oil recovery

and reservoir pressure maintenance method. However, the

choice of the salinity of water for sweeping oil from a

reservoir has rarely been associated with rock mineralogy.

This was due to the lack of experimental data on the effect

of injecting water salinity into the oil recovery process. To

date, after a sufficient number of laboratory and field tests,

enough evidence has been provided of a strong correlation

between injected water salinity and the efficiency of oil

displacement.

The first attempt to investigate the low salinity

effect was taken by Martin [1]. He concluded that the

injection of fresh water can cause better oil displacement

due to the effects of clay. Bernardin 1967 observed that

upon the reduction of the injected water’s salinity from

150,000 ppm to 1000 ppm, the IOR increased up to 6%

most probably due to clay swelling and fine migration

indicated by an increase of the pressure drop [2].

Beginning in the 1990s, research on the low

salinity effect (LSE) was considerably advanced [3-7]. For

example, Tang and Morrow’s results suggested that the

mechanism of fine migration is responsible for improved

oil recovery and hence the existence of clay content is

necessary for the successful application of LSWF [6,7].

On the contrary, Lager et al. and Zhang et al.did not detect

the fine migration mechanism, as no clay particles were

found in the effluent stream [8,9].

Nasr El Din and hiscolleagues have conducted

extensive research on defining LSWF mechanisms [10-

17]. For example, Shehata and Nasr-El-Din performed

contact angle measurements and proved that LSWF alters

rock wettability [16]. Also, coreflood experiments on

Berea cores showed that low salinity water recovered

more oil compared with reservoir brine in the secondary

mode. However, this did not enhance oil recovery in the

tertiary mode. Furthermore, it was shown by Alotaibi and

Nasr-El-Din that decreasing the salinity does not

necessarily change interfacial tension (IFT) in the brine/n-

dodecanesystem [18].

There have been a number of LSWF pilot tests

(McGuire et al., 2005; Seccombeet al., 2010; Webb et al.,

2004) [19-21]. For example McGuire et al. reported that

after the injection of low salinity water, the oil recovery

factor increased to 19% for four wells located at Endicott

Field [19]. In contrast, Skrettingland et al., Thyne and

Gamage reported unsuccessful LSWF pilot tests with no

incremental increase in oil production [22,23].

Only a few papers have been dedicated to the

study of the effect of brine salinity on the interfacial

behavior between brine and heavy oil. Gachuz-Muro and

Sohrabi have shown that the interaction of distilled water

with two heavy crude oil samples resulted in the reduction

of their viscosities from 1686 and 730 cp on 14.3% and

35.3% respectively at an ambient temperature. The authors

attribute this to the presence of resins and asphaltens

which cause a reduction in viscosity after interaction with

brine. They also reported that a change in the viscosity of

oil is not necessarily due to the temperature [24]. It was

also shown by Gachuz-Muro and Sohrabi that by properly

adjusting brine composition, it is possible to incrementally

recover a significant amount of heavy oil from carbonate

cores due to the alteration in wettability [25].

Recent experimental studies of Gachuz-Muro et

al. on both limestone and dolomite rocks suggest that the

chemical reaction between the injected fluid and basic

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compounds of crude oil generates acidic water which in

turn causes the dissolution of carbonate rocks. This

explains why the so called ‘smart water’ injection

improves oil recovery in carbonate reservoirs. Moreover,

the results suggest that acidic crude oil cannot generate

acidic water [26].

Alzayer and Sohrabi presented the results of a

numerical simulation of heavy oil recovery using low

salinity waterflooding augmented with polymer flooding.

The combined low salinity water and polymer flooding

resulted in 10% of IOR, while LSWF allowed only 5% of

IOR [27].

Abass and Fahmi studied the effect of hot LSW

on heavy oil recovery compared with hot high salinity

waterflooding. Three types of oil (two extra heavy and

medium heavy types with a viscosity of 1700, 1000 and

700 cp respectively) were used. It was found that low

salinity hot water yielded 20% more oil production. The

authors explain this by wettability alteration and fine

migration due to the LSE [28].

This study shows that the proper combination of

EOR methods with low salinity water flooding could

demonstrate a synergetic effect. Also, today there are

emerging technologies which enable the production of

fresh water [29,30].

On the basis of the literature review, several

mechanisms of low salinity waterflooding can be drawn:

Fine migration [2,7]

Increased pH [19]

Multicomponent ion exchange (MIE) [8]

Double layer expansion (DLE) [13,31,32]

All of these above mentioned mechanisms are

likely to change the wettability of rock’s surface [11].

Though, many studies show that clays play key role in the

performance of low salinity waterflooding [6,33-36].

Fine migration and clay swelling are considered

negative phenomenon in the oil and gas industry,

especially in the operations of well drilling [37]. However,

injecting fresh water could demonstrate mobility control

by induced fines migration in clay rich reservoirs [38].

Clays are naturallyoccurring mineral in the

reservoir rock compositions and its presence impact on the

permeability. Mainly they are divided into four groups

[39,40].

Kaolinite - a highly stable (non-swelling);

Illite- (non-swelling);

Smectite (montmorillonite) - swelling;

Chlorite - lower swelling capacity;

Mixed layer clays.

The objectives of this study are to evaluate the

impact of the salinity of the injected fluid on high viscous

oil recovery after primary high salinity water flooding.

Asporous medium, strong water - wet (hydrophilic) and

preferentially oil-wet (hydrophobic) unconsolidated sand

packs were used. The outcome of this study is to bring

new insights on the role of salinity of injected water and

rock wettability and composition in oil recovery from

heavy oil sandstone reservoirs.

EXPERIMENTAL STUDIES Materials porous media: Water-wet fluvial sand

(river sand) and preferentially oil-wetsand from the

Karabulak oilfield (Kazakhstan) were used to create sand

pack models. The models were 6 cm (2.36 in.) in length

and 3 cm (1.18 in.) in diameter. The porosity and

permeability of each sand pack were measured prior to the

experiments with a sand pack flooding apparatus. The

wettability of the sands was determined by a contact angle

measurement at ambient temperature in the presence of

reservoir brine. The contact angle of oil drops on sand

layers turned out to be as follows, on fluvial sand 48º and

on Karabulak sand 107º (Figure-2). According to

Anderson fluvial sand is considered water-wet, whereas

Karabulak sand is considered preferentially oil-wet [41].

The mineral composition of two sand samples was

evaluated using X-ray diffraction Analysis

(PanalyticalX'Pert Diffractometer (USA)) (Table-1). It is

noticeable that preferentially oil-wet sand contains a

significant amount of kaolinite (17%). Figure-1 shows the

texture of both water-wet and preferentially oil-wet sand

grains under a microscope. On the one hand, preferentially

oil-wetsand grain has rough surface with acute angles. On

the other hand, water-wet sand grain has a smooth and

round surface.

Table-1. Mineralogy of the sand packs.

Water-wet sand Preferentially oil-wet sand

Mineral wt% Mineral wt%

Anorthite 57 Quartz, 64

Albite 25 Kaolinite 17

Quartz 11 Hedenbergite 9

Orthoclase 7 Albite 9

Calcite 1

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a) b)

Figure-1.Textures of the water-wet (a) and preferentially oil-wet (b) sand grains under a microscope.

a) 48º b) 107º

Figure-2. Contact angle measurement of oil drops on the water-wet sand (a) and preferentially oil-wet

Karabulak sand (b) layers in the presence of reservoir brine.

Crude oil: Viscous oil from Karazhanbas oil

field (Kazakhstan) was used in this study. The total acid

number was measured using a Metrahom 905 Titrando in

the lab. Rheological properties were measured using a

RheolabQC (Anton PAAR) viscometer. Some properties

of the oil are provided in Table-2 and Table-3.

Table-2. Properties of Karazhanbas crude oil.

Dynamic viscosity

@ 30ºC, cP

Density,

g/cm3

Acid number, (mg/KOH of oil)

*API Asphaltenes,

% Resins,% Paraffins,%

346 0.935 0.70 9,69 25,8 4,1 1,5

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Table-3. Results of RFA analysis of Karazhanbas

crude oil.

Compound Concentration, %

Al 0.365

Si 0.243

P 1.298

S 94.778

Ca 1.507

V 1.340

Cr 0.008

Fe 0.072

Ni 0.389

Brines: Synthetic reservoir brine (RB) was used

for the saturation of the sand packs and primary water

flooding. Fresh (C<100 ppm) water (FW) was used to

model low salinity flooding after primary brine

flooding.The composition of the synthetic reservoir brine

is listed in Table-4.

Table-4. The composition of the synthetic reservoir brine.

Salt C,g/l

NaCl 64

CaCl2 12

MgCl2 17

TDS 93

EXPERIMENTAL PROCEDURE All experimental procedures were conducted at

an ambient temperature of 30 °C (the reservoir

temperature at Karazhanbas oilfield). The overburden

pressure was maintained constantly for all tests at 2 MPa

(290 psi). Firstly, evacuated sand packs were saturated

with reservoir brine. To establish connate water saturation,

the brine-saturated sand packs were flooded with crude oil

at a rate of 0.1 cm3/min. Two pore volumes of crude oil

were injected to ensure that no more water was produced.

Initial water and oil saturation were calculated using a

material balance equation. After establishing initial

conditions, the sand packs were left inside of the sand

pack holder over night to reach ionic equilibrium. Water

flooding experiments consisted of the injection of two

pore volumes of RB followed by two pore volumes of FW

at 0.1cm3/min during a constant recording of the injection

pressure and oil recovery factor (ORF). The choice of

injection of two pore volumes of fluid can be explained by

the limits of volume in the injection pump of the

apparatus. All experiments were conducted by

coreflooding apparatus UIK-S(2) (Russia) (Figure-3).

Figure-3.The picture of the coreflooding apparatus UIK-S(2).

RESULTS AND DISCUSSIONS

Sand pack flooding experiment #1. The first

waterflood experiment was conducted on a water-wet

fluvial sand pack. The petrophysical parameters of the

sand pack are given in Table-6.The sand pack model was

made from 250 μm size sand fraction. The injection of

reservoir brine recovered 37% of OOIP (Figure-4). During

injection no clay fines were observed in the effluents. The

pressure profile was stable across the sand pack.The

continuous injection of fresh water resulted in an IOR of

4%. No clay fines and severe pressure changes were

observed.

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Figure-4.The performance of sand pack flooding test #1. Water-wet sand pack,

sand fraction size is 250 μm.

Sand pack flooding experiment#2.The second

experiment was conducted on preferentially oil-wet sand.

The fraction of sand grain sizes turned out to be as follows

(Table-5):

Table-5.The fraction of sand grain sizes of the model in test#2.

Sand

fraction, μm 250 125 63 45 45> sum

% 88,5 9,38 1,31 0,44 0,37 100

The initial parameters of the sand pack sample

are given in Table-6. The injection of reservoir brine

resulted in 40% of oil recovery. The pressure profile was

stable during brine flooding. However, after 0.5 pore

volumes of fresh water had been injected into the model,

ORF began to increase until 19% of IOR was reached

(Figure-5). It is remarkable that the increase of ORF was

accompanied with a noticeable increase in injection

pressure from 0.02 up to 0.03 MPa. We suggest that fine

migration may have caused the pressure to increase.

Furthermore, the visual analysis of aqueous effluents

demonstrated that it contained precipitation (Figure-

6).This corresponds with the works of Zhang et al [9] and

Y. Li [42].

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Figure-5. The performance of the sand pack flooding test#2, oil-wet sand.

a) b)

Figure-6. The effluent samples of sand pack flooding test #2, a) effluent sample during

the injectionof reservoir brine; b) effluent sample during the injection of fresh water.

Sand pack flooding experiment#3 was performed

ona water-wet sand pack (Figure-7). In this test we

repeated the sand fractions of test #2. We added the same

amount of water-wet sand fractions using 250 μm, 125 μm, 63 μm, 45 μm and less than 45 μm. of sand fractions to see whether or not the recovery factor would rise. The

initial parameters are given in Table-6. The results reflect

the value of oil recoveries obtained in sand pack

floodingtest#1. RB recovered 37%, while FW recovered

4% of OOIP. Even though we added smaller fractions of

the water-wet sand, no particles were produced and

pressure was stable during the experiment. This result

suggests that thecomposition of the rock plays more a

significant role in LSWF than its fractional composition.

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Figure-7.The performance of the sand pack flooding test#3, water-wet

sand with different sand fractions in the model.

Sand pack flooding test#4 was performed on

preferentially oil-wet sand(Figure-8). This sand pack

contained only 250 μm (85%) and 125 μm (15%) sand fractions. The initial parameters are given in Table-6. The

additional oil recovery after injecting fresh water resulted

in 12% of OOIP. The sand pack flooding tests confirmed

that fresh water had a positive effect on the preferentially

oil-wet sand pack samples. Also, the pressure profile

partially followed a recovery factor peaking at 0.037 MPa

followed by a decrease to the initial point of 0.027 MPa.

The decreasing of the pressure at the end implies that no

clay swelling took place. Production of clay particles in

the effluents was observed and this was matched by the

pressure profile.

Figure-8. The performance of the sand pack flooding test#4, oil-wet sand.

Sand pack flooding tests #5 and #6. In this

study we reproduced test#2 and test#4 for the repeatability

of the tests. Both sand pack flooding experiments were

conducted on preferentially oil-wets and packs and

contained an equal amount of sand fractions as in previous

experiments #2 and #4. The initial parameters are given in

Table-6. The results are given in Table-7. The difference

between the experiments was 15% and 20% respectively.

We consider this an experimental error that occurred

during the preparation of the tests. In general, the same

dynamics in experiments can be seen (Figure-9 and

Figure-10). The pressure behavior was similar to that of

the previous experiments with preferentially oil-wet sand

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packs. Clay fines were produced during fresh water injection.

Figure-9. The performance of the sand pack flooding test#5

(repetition of test #4).

Figure-10. The performance of the sand pack flooding test#6

(repetition of test #2).

Glass pieces and plastic spheres packs flooding tests #7 and #8.The glass pieces with a grain size of 500

μm (0.5mm) were used to model water-wet media. Plastic

spheres with a size of 1000 μm (1mm) were also used to

model oil-wet media. The prime objective of these

experiments was to investigate the sole impact of the

wettability nature of the porous media on the recovery

factor while injectingfresh water. It is common knowledge

that a glass surface is considered hydrophilic and a plastic

surface is considered hydrophobic and that these materials

do not contain any clay. The test procedure was the same

as that of the previous tests. The tests revealed that the oil

recovery from glass packs was almost the same as that

obtained on water-wet sand packs. By contrast, RB

injection into the plastic spheres pack demonstrated the

least total oil recovery of 28.5% of OOIP (Table-6) among

the experiments. Decreasing the brine salinity resulted in

4.5% of additional oil recovery. The pressure profile of

the glass pack during the brine injection was stable with a

slight climb at the end of the test. The pressure profile of

the plastic pack fluctuated around 0.05MPa with periodic

peaks at 0.1 MPa during the injection of fresh water

(Figure-11and Figure-12).

The plastic pack flooding test showed that for the

performance of low salinity water flooding the

mineralogical composition of rock is more important in

comparison with its wettability nature.

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Figure-11. The performance of the glass pieces flooding test#7.

Figure-12. The performance of the plastic spheres flooding test#8.

Table-6. The initial parameters of sand packs of the experiments.

Sand pack Pore

volume, cm3

Porosity

Absolute

permeability,

Darcy

Connate

water

saturation

Initial oil

saturation

Exp#1 (water-wetsand) 14 0,33 12 0,25 0,75

Exp#2 (preferentially oil-wet

sand) 13,5 0,32 7 0,23 0,77

Exp#3 (water-wetsand) 13 0,3 7,6 0,23 0,77

Exp#4 (preferentially oil-wet

sand) 14 0,33 11 0,22 0,78

Exp# 5(4*) (preferentially oil-wet

sand) 14 0,32 8,7 0,26 0,74

Exp#6(2*) (preferentially oil-wet

sand) 13 0,3 6 0,25 0,75

Exp#7 (glass) 14.5 0,34 3.3 0,12 0,82

Exp#8 (plastic spheres) 12 0,29 4 0,08 0,92

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Table-7. Summary of sand pack flooding experiments @ 30ºC.

Experiment no. Slug type Slug size

(PV) Injection rate

(ml/min)

IOR (%

OOIP) Totaloilrecovery

Ex#1 (water-wet )

Reservoirbrine

(93g/l) 2 0,1 37

41

Freshwater 2 0,1 4

Ex#2 (preferentially oil-

wet)

Reservoirbrine

(93 g/l) 2 0,1 40

59

Freshwater 2 0,1 19

Ex#3 (water-wet)

Reservoirbrine

(93 g/l) 2 0,1 37

41

Freshwater 2 0,1 4

Ex#4 (preferentially oil-

wet)

Reservoirbrine

(93 g/l) 2 0,1 44

56

Freshwater 2 0,1 12

Ex# 5(4*) (preferentially

oil-wet)

Reservoirbrine

(93 g/l) 2 0,1 42

52

Freshwater 2 0,1 10

Ex#6(2*) (preferentially

oil-wet)

Reservoirbrine

(93 g/l) 2 0,1 35,6

51,6

Freshwater 2 0,1 16

Ex#7 (glass)

Reservoirbrine

(93 g/l) 2 0,1 40

47,4

Freshwater 2 0,1 7,4

Ex#8 (plasticspheres)

Reservoirbrine

(93 g/l) 2 0,1 24

28,5

Freshwater 2 0,1 4,5

SUMMARY AND CONCLUSIONS The experiments performed on different sand

packs showed that fresh water flooding after a reservoir

brine flooding recovered more oil from preferentially oil-

wet sand packs compared to the water - wet sand. This can

be explained by the presence of kaolinite. Moreover, the

production of clay fines was observed in all effluent

samples of preferentially oil-wet sand pack flooding tests.

We assume that, extreme reduction of salinity of the

injecting water impacts on the migration of kaolinite as it

is a non-swelling clay therefore it could be detached and

migrated plugging water saturated zones and redirecting

water flow into oil-reach pores, which leads to the

incremental oil production and higher pressure drop.

The experiments performed on the water-wet sand packs

didn’t demonstrate additional oil recovery by fresh water.

We explain this by two reasons:

a) The water-wet sand packs didn’t contain any clay.

b) The wettability of the surface was hydrophilic, which

can’t lead further increasing of wettability of the rock,

so most of the oil was recovered by reservoir brine.

The coreflooding experiments on plastic beads

demonstrated little response to the salinity reduction,

which shows that wettability changeis negligible in the

mechanisms of low salinity wateflooding.

The literature review and this research suggest

that by injecting extremelylow salinity water (in our case it

was fresh water) in the reservoirs with a specific rock

composition can demonstrate additional oil recovery

without adding any chemicals to the water. Also, by

injecting fresh water the induced innate mobility control

technologiescan be developed by controlled fine

migration, taking into account the rock composition.

The results provide evidence of potential oflow

salinity water as an improved oil recovery method in the

reservoirs with high content of kaolinite and with high

viscosity oil.

ACKNOWLEDGEMENTS The authors would like to acknowledge Sarkyt

Kudaibergenov and Aleksey Shakhvorostov for their help

with experimental work. Laboratory of engineering profile

at Kazakh National Research Technical University for use

of their equipment and Karazhanbasmunai JSC for

providing the crude oil samples.

Abbreviation

HSW = high salinity waterflooding

LSW = low salinity waterflooding

IOR = incremental oil recovery

IFT = interfacial tension

OOIP = oil original in place

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ORF = oil recovery factor

FW = fresh water

RB = reservoir brine

RFA = X-ray fluorescence analysis

XRD = X-ray diffraction

TDS = total dissolved solids

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