**3. Enhanced oil recovery using low-salinity waterflooding**

## **3.1 Concept of mobility ratio**

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**2. Secondary recovery using waterflooding**

of oil still unrecovered [2].

modified waterflooding.

recovery process.

Morrow and his coinvestigators [5].

the world's petroleum originates from sandstone reservoirs. Next section will cover LSWF process in details.

energy must be added to the reservoir to maintain the reservoir pressure in order to produce additional oil. This stage is called secondary oil recovery, which utilizes various mechanisms including gas injection and waterflooding into the reservoir to force and displace the remaining residual oil. This process is typically successful in producing around 30% of the oil reserves after natural depletion, leaving 50–80%

The last stage of hydrocarbon recovery is known as enhanced oil recovery (EOR), which uses different practices such as chemical flooding, miscible flooding and thermal methods to extract the hydrocarbon fluid left behind the primary and secondary recovery. EOR has the capability of increasing oil recovery up to 75% of OOIP by improving the mobility of oil via modifying fluid properties [3]. Some examples of EOR techniques implemented in the oil industry are polymer flooding, steam injection, alkaline flooding, in situ combustion and

Conventional waterflooding is a secondary oil recovery approach that consists of water injection to improve the oil production from the subsurface. It is typically performed after the primary recovery which utilizes the natural energy available in the reservoir. The main purpose of secondary recovery is to displace hydrocarbons

The improved oil production using waterflooding was first discovered in early

1865 following an accidental flooding of water in Pithole City, Pennsylvania. This was the result of leaks from surface water and shallow water which entered the drilled holes. It is revealed that the oil recovery factor by waterflooding is significantly high compared to the natural depletion. The first applied application of waterflooding was attempted in Pennsylvania's Bradford field, in 1924, which then grew and was widely applied in many fields in the subsequent decades [4]. Following nationwide waterflooding implementation in petroleum industry, many attempts were conducted in understanding mechanism, planning and optimizing the process. Due to its simplicity and reliability, the waterflooding technique has been worldwide implemented and been considered for most of conventional oil reservoirs to extract more hydrocarbon after the primary

The conventional waterflooding process involves water injection into the reservoir formation in which the process is generally done with consideration of the economic factors and also based on the water compatibility with the present reservoir brine to avoid formation damage. However, in the early 1990s, a number of researchers experimentally investigated the effect of water composition and found that it plays a significant role in the oil recovery. After this, the potential of lowsalinity waterflooding (LSWF) in EOR applications was observed and developed by

Furthermore, extensive water coreflood experiments have been conducted and addressed the benefits of low salinity in the EOR process. Most of these experiment results showed that when the injected water salinity is lower than the formation water salinity, a higher oil recovery up to 40% is achieved for both secondary and tertiary recoveries [6]. However, LSWF has gained vast interest in the petroleum industry due to its practical advantages compared to other chemical EOR methods. LSWF is an emerging EOR technology, and it has a promising future since half of

towards the production wells while maintaining the reservoir pressure.

**94**

As seen earlier waterflooding involves the injection of water into the reservoir is by far the most widely utilized solution for improving oil recovery. Practically any oil field which does not have an aquifer support will be considered for waterflooding to maintain the reservoir pressure and improve production rate [7]. A reservoir's compliance or suitability for waterflooding to increase oil production can be done by evaluating formation and fluid parameters such as formation rock type, porosity, permeability, saturation and distribution of reservoir fluids and optimum time of water injection [8]. Combined effect of these factors can determine the ultimate recovery of hydrocarbon and its economic revenues depicting the viability of carrying out waterflooding for a specific reservoir condition.

The efficiency of a flooding process can be qualitatively evaluated via defining the mobility ratio, especially end-point mobility ratio. As the term implies, endpoint mobility ratio is measured at the end-point saturation of a single-phase fluid and can be written as shown in Eq. (1). *<sup>M</sup>* <sup>=</sup> \_

## [Eq. (1).

 $\mathcal{M} = \frac{\lambda\_{\text{water}}}{\lambda\_{\text{oil}}} = \frac{k\_{\text{vo}}\mu\_{\text{v}}}{k\_{\text{vo}}\mu\_{\text{v}}} = \frac{k\_{\text{v}\text{vo}}\mu\_{\text{o}}}{k\_{\text{vo}}\mu\_{\text{u}}}$ 

where,

M end-point mobility ratio

<sup>λ</sup>*water* water mobility (mD)

<sup>λ</sup>*oil* oil mobility (mD/cP)

*krw* relative permeability of water (mD)

*kro* relative permeability to oil (mD)

*μo* oil viscosity (cP)

*μw* water viscosity (cP)

When the value of end-point mobility ratio is less than one, it indicates that the performed flooding is stable, while for a value of more than one, flooding process is unstable due to a phenomenon known as 'viscous fingering'. Considering an oil–water system, stable flooding signifies that oil displacement will effectively take place if the injected water behaves like a piston and pushes oil to the intended point [9]. On the other hand, viscous fingering refers to early and continuous breakthrough of injected fluid as a result of large difference in viscosity between water and oil phase. A higher value of mobility ratio implies reducing waterflooding effectiveness as the volumetric sweep efficiency reduces [10].

### **3.2 Concept of wettability**

In understanding the process of oil recovery, formation wettability knowledge is important as it describes the reservoir performance via defining the fluid flow and distribution. Being one of the most significant factors of LSWF, it is important to comprehend wettability phenomenon appropriately to prevent any incorrect assumptions which may lead to permanent formation damage.

Wettability can be defined in a system which consists of two immiscible fluids in contact with a solid surface (rock). In the presence of such system, wettability can be described as the tendency of one fluid to adhere to the rock surface to be in contact with one fluid than the other. In the situation of two-phase immiscible fluid, one fluid attaches strongly to the rock surface while displacing the other fluid [11]. In reference to wettability concept, fluids can be classified into wetting or non-wetting fluid. A wetting fluid balances its forces and adheres to the rock at a

specific contact angle, while the non-wetting fluid will have minimal or no contact with the rock.

In a reservoir system, when the reservoir fluids present in the porous medium are oil and water, wettability can be described as the preference of the rock to be in contact with either oil or water or both fluids. In an oil field, reservoir rock wettability is typically described as either water-wet or oil-wet. If the reservoir is described to be water-wet, it means that the water phase is retained on the pore wall either small or large by capillary pressure, while the oil phase occupies the pore space [12]. On the other hand, an oil-wet reservoir implies that oil phase is adhered to the rock pores, while water phase occupies the centre of pores. There are a number of techniques in which wettability can be quantitatively measured by the determination of contact angle, the Amott method and US Bureau of Mines (USBM) method [13]. The surface energies of a water, oil and solid system can be expressed by Young's equation; Eq. (2) can be deduced.

$$
\sigma\_{ow} \cos \Theta = \sigma\_{\alpha} - \sigma\_{\alpha \alpha} \tag{2}
$$

where,


As a typical practice, the contact angle measurement is performed through the aqueous phase, and it identifies wettability as seen in **Figure 1**. For a reservoir rock containing only oil and water, a contact angle of less than 90° indicates that the reservoir rock is water-wet, but when the contact angle is more than 90°, it denotes the reservoir rock is oil-wet. Moreover, a strong water-wet rock system can present when the fluid-rock contact angle approaches to 0°, while a strong oil-wet rock can be described when the contact angle approaches to 180° [13]. When both fluids (oil, water) are in contact with the rock surface, the reservoir rock can be described to be in intermediate/neutral-wet condition.

**Figure 1.** *Wettability of the crude oil/brine/rock system [13].*

### *Potential of Low-Salinity Waterflooding Technology to Improve Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.88082*

*Enhanced Oil Recovery Processes - New Technologies*

equation; Eq. (2) can be deduced.

<sup>θ</sup> contact angle (degree)

in intermediate/neutral-wet condition.

*Wettability of the crude oil/brine/rock system [13].*

<sup>σ</sup>*ow* oil and water interfacial energy (dyne/cm) <sup>σ</sup>*os* oil and solid interfacial energy (dyne/cm) <sup>σ</sup>*ws* water and solid interfacial energy (dyne/cm)

with the rock.

where,

specific contact angle, while the non-wetting fluid will have minimal or no contact

In a reservoir system, when the reservoir fluids present in the porous medium are oil and water, wettability can be described as the preference of the rock to be in contact with either oil or water or both fluids. In an oil field, reservoir rock wettability is typically described as either water-wet or oil-wet. If the reservoir is described to be water-wet, it means that the water phase is retained on the pore wall either small or large by capillary pressure, while the oil phase occupies the pore space [12]. On the other hand, an oil-wet reservoir implies that oil phase is adhered to the rock pores, while water phase occupies the centre of pores. There are a number of techniques in which wettability can be quantitatively measured by the determination of contact angle, the Amott method and US Bureau of Mines (USBM) method [13]. The surface energies of a water, oil and solid system can be expressed by Young's

As a typical practice, the contact angle measurement is performed through the aqueous phase, and it identifies wettability as seen in **Figure 1**. For a reservoir rock containing only oil and water, a contact angle of less than 90° indicates that the reservoir rock is water-wet, but when the contact angle is more than 90°, it denotes the reservoir rock is oil-wet. Moreover, a strong water-wet rock system can present when the fluid-rock contact angle approaches to 0°, while a strong oil-wet rock can be described when the contact angle approaches to 180° [13]. When both fluids (oil, water) are in contact with the rock surface, the reservoir rock can be described to be

σ*ow* cosθ = σ*os* − σ*ws* (2)

**96**

**Figure 1.**

Wettability could greatly affect the reservoir rock petrophysical properties, for instance, residual saturation, capillary pressure, relative permeability and end point of relative permeability curves [14]. The crossover point and the relative permeability end points of wetting and non-wetting phases are related to wettability as shown in **Figure 2**. For a strong water-wet rock, the relative permeability curves will crossover at a wetting phase saturation point of greater than 0.5, while a strong oil-wet rock relative permeability curves will crossover at a wetting phase saturation point of lesser than 0.5. A crossover point at a saturation of 0.5 and equal end points of relative permeability curve imply that the reservoir rock is in neutral-wet condition [16].

The alteration in reservoir rock wettability may possibly occur naturally during production, or it can be modified using thermal or chemical method. Initially, most of the reservoir formations are in the state of strong water-wet due to the deposition process that saturates reservoir completely with water [17]. The migration of hydrocarbon fluid (especially oil) may cause a change in the rock wettability to oil-wet, or the rock may maintain its wettability as water-wet. Mugele et al. [18] reported that the rock wettability can be altered to be more water-wet via the adsorption of divalent cations, subsequently allowing better mobilization of oil for production. In addition, several studies strongly suggest that the adsorption of divalent cations such as Ca2+ and Mg2+ changes the initial rock wettability towards more water-wet [19]. This is an important observation that describes the LSWF mechanism which results in incremental oil recovery and will be deeply discussed in the upcoming sections.

### **3.3 Role of crude oil, brine and reservoir rock on wettability**

It is commonly known that oil reservoirs can have various alterations of wettability depending on the oil and rock and also the composition and amount of the brine phase. Crude oil/brine/rock (COBR) interactions are utilized to produce wetting conditions in laboratory core samples which are more representative of wetting in an oil reservoir than either a strongly oil-wet or water-wet. Anderson [20] stated that the original strong water-wetness of most reservoir minerals can be changed via the polar compounds adsorption and/or the deposition of organic matter that was initially in the crude oil. He also reported the surface-active agents present in

**Figure 2.** *Effect of wettability on relative permeability curve [15].*

the oil that are widely believed to be polar compounds that comprise nitrogen, oxygen and/or sulfur. Such compounds have a polar and a hydrocarbon end. He noted that the polar end is adsorbed on the rock surface, exposing the hydrocarbon end and making the rock surface more oil-wet. Furthermore, to the oil composition, the degree of wetting conditions which is altered by these surfactants can also be determined by various factors that are the temperature, pressure, mineral surface and brine chemistry, including pH and ionic composition.

Buckley et al. [21] found that some factors are affecting the rock wetting upon contact with crude oil, including composition of both the oil and brine, temperature and duration of aging in oil and initial water saturation. The chemistry of the brine phase was noticed to change the rocks wettability, which shown that the brine pH is also significant in verification of wettability and other interfacial properties of the COBR system. They also indicated that similar factors affect measurements of contact angle using asphaltic crude oil and two sodium chloride solutions of different pH to alter the wetting of two core formations. They noted in cores that there are further complexities in wetting related to rough surfaces, converging and diverging pore shapes and heterogeneous mineralogy. Superimposed on all these sources of heterogeneity in the porous media is the ability of crude oil components to adsorb onto mineral surfaces and change their wetting properties. They summarized that changing pH of aqueous phase affects initial water saturation (Swi) in cores with low-ionic-strength NaCl solutions. Moreover, pore coatings may control wetting alteration in the porous media thus the COBR interactions are not similar to predicted values.

Tang and Morrow [22] performed a study on the effect of salinity and oil composition on wettability behaviour and observed that there are some possible mechanisms by which COBR interactions control wettability and efficiency of oil recovery. They noted that acid–base interactions can define oil-brine and brinesolid surface charges, and also direct adsorption from crude oil onto a dry surface is ascribed to polar interactions. It is noticed that alterations in wettability resulting from instability of a water film take place almost instantaneously. Furthermore, adsorption by ion binding takes place through attachment of polar components in the crude oil to specific surface sites on the solid surface by multivalent ions. Surface precipitation is recognized by conditions of poor solvency of asphaltenes in the oil phase. They noted that molecular association, including ion binding of crude oil components at the interface of oil–water, could promote lateral aggregation and the formation of an organic mat that may still be largely separated from the solid surface by a thin water film. They concluded that wetting variations of a rock induced by crude oil are related to changes in solvency of the crude oil with respect to its heavy polar components.

Cuiec [23] explained many experimental condition contributions to understand oil/rock interactions, which are responsible on the occurrence of oil-wet reservoirs. He noticed that some intermediate fractions of crude oil samples might change the rocks' surface properties depending on the type of formation. He also reported the role of asphaltenes in crude oil/solid interactions through correct correlation between wettability and asphaltene content for a set of reservoirs.

Clementz [24] observed that clay mineral properties are irreversibly altered by adsorption of heavy crude ends. Therefore, this alteration causes reduction in rock sensitivity to injected fluids since rock wettability is altered from water-wet to neutral. He noted further that adsorption of surfactants is decreased, while rock property measurements are changed from irreversibly altered cores. The extent of this interaction is subjected to the type of clay minerals in the rock, the composition of heavy crude ends and the interaction environment. He had seen that after the adsorption took place, a clay-organic complex is formed which is hydrophobic

### *Potential of Low-Salinity Waterflooding Technology to Improve Oil Recovery DOI: http://dx.doi.org/10.5772/intechopen.88082*

*Enhanced Oil Recovery Processes - New Technologies*

and brine chemistry, including pH and ionic composition.

the oil that are widely believed to be polar compounds that comprise nitrogen, oxygen and/or sulfur. Such compounds have a polar and a hydrocarbon end. He noted that the polar end is adsorbed on the rock surface, exposing the hydrocarbon end and making the rock surface more oil-wet. Furthermore, to the oil composition, the degree of wetting conditions which is altered by these surfactants can also be determined by various factors that are the temperature, pressure, mineral surface

Buckley et al. [21] found that some factors are affecting the rock wetting upon contact with crude oil, including composition of both the oil and brine, temperature and duration of aging in oil and initial water saturation. The chemistry of the brine phase was noticed to change the rocks wettability, which shown that the brine pH is also significant in verification of wettability and other interfacial properties of the COBR system. They also indicated that similar factors affect measurements of contact angle using asphaltic crude oil and two sodium chloride solutions of different pH to alter the wetting of two core formations. They noted in cores that there are further complexities in wetting related to rough surfaces, converging and diverging pore shapes and heterogeneous mineralogy. Superimposed on all these sources of heterogeneity in the porous media is the ability of crude oil components to adsorb onto mineral surfaces and change their wetting properties. They summarized that changing pH of aqueous phase affects initial water saturation (Swi) in cores with low-ionic-strength NaCl solutions. Moreover, pore coatings may control wetting alteration in the porous media thus the COBR interactions are not similar to

Tang and Morrow [22] performed a study on the effect of salinity and oil composition on wettability behaviour and observed that there are some possible mechanisms by which COBR interactions control wettability and efficiency of oil recovery. They noted that acid–base interactions can define oil-brine and brinesolid surface charges, and also direct adsorption from crude oil onto a dry surface is ascribed to polar interactions. It is noticed that alterations in wettability resulting from instability of a water film take place almost instantaneously. Furthermore, adsorption by ion binding takes place through attachment of polar components in the crude oil to specific surface sites on the solid surface by multivalent ions. Surface precipitation is recognized by conditions of poor solvency of asphaltenes in the oil phase. They noted that molecular association, including ion binding of crude oil components at the interface of oil–water, could promote lateral aggregation and the formation of an organic mat that may still be largely separated from the solid surface by a thin water film. They concluded that wetting variations of a rock induced by crude oil are related to changes in solvency of the crude oil with respect

Cuiec [23] explained many experimental condition contributions to understand oil/rock interactions, which are responsible on the occurrence of oil-wet reservoirs. He noticed that some intermediate fractions of crude oil samples might change the rocks' surface properties depending on the type of formation. He also reported the role of asphaltenes in crude oil/solid interactions through correct correlation

Clementz [24] observed that clay mineral properties are irreversibly altered by adsorption of heavy crude ends. Therefore, this alteration causes reduction in rock sensitivity to injected fluids since rock wettability is altered from water-wet to neutral. He noted further that adsorption of surfactants is decreased, while rock property measurements are changed from irreversibly altered cores. The extent of this interaction is subjected to the type of clay minerals in the rock, the composition of heavy crude ends and the interaction environment. He had seen that after the adsorption took place, a clay-organic complex is formed which is hydrophobic

between wettability and asphaltene content for a set of reservoirs.

**98**

predicted values.

to its heavy polar components.

and very stable. The development of swelling clays is decreased, and clay surface area and cation exchange capacity are decreased as well. As a result, he revealed that the practical implication of these problems indicates some sort of spotted coverage of the surface and leads to discuss the role of an adsorbed layer on the rock wettability. The existence of this surface film would certainly affect oil recovery in a rock system. He recommended that it cannot be stated a priori that oil recovery from the rock having a neutral wettability will be less than that from the water-wet system. In addition, he reported that the recovery would most undoubtedly rely on the nature of drive fluid and its interaction with reservoir minerals. Finally, he concluded that it is very important to identify potential alterations to core properties, which take place as a result of core handling. The absorbed layer can either be formed or damaged, and any rock property measurements, which count on the nature of the clay minerals present, would be affected by the existence of the adsorbed layer.

Brown and Neustadter [25] studied the wettability performance of oil/water/ silica systems based on contact angle measurements. They reported that the recovery efficiency of crude oil from a porous media using water displacement depends on the rock wettability. This conclusion was based on the relative tendency of both the aqueous and oil phase to coat the solid surface and, therefore, to occupy the rock pores under the action of capillary forces. They also found that the existence of monovalent ions can affect wetting conditions by suppressing the charge effects with no effect at low concentration of NaCl and behave differently at high concentration and extremes of pH. By contrast to the effect of monovalent ions, they have seen that the seawater can provide a strongly oil-wetted surface, independent of pH, even when it is diluted with distilled water. Furthermore, they noticed the same performance with synthetic seawater that was applied to determine if the original seawater can affect the wettability by reason of its protein or other nonsalt components. The results obtained with NaCl were as expected considering the charge interaction model, but using seawater indicated that divalent ions had a very noticeable effect. In addition, they conducted a study to examine the effect of divalent ions and observed that there are specific interactions between different oil crude samples and the divalent ions can take place. They suggested that alterations in wettability are not contributed to general electrical double-layer compression at low electrolyte concentrations. They also observed that divalent ions can create bridges between specific petroleum crude surfactant species and the silica surface. In conclusion, for systems of crude oil/silica/distilled water, the wettability strongly depends on pH due to activation of the crude oil surfactants by the aqueous phase. When pH value is high, the water film can stabilize between the oil film and the silica surface by charge repulsion, while at low pH values, charge attraction between the positively charged crude oil surfactants and the negative rock surface promotes wetting oil surface. Moreover, crude oil/rock systems, which are preferentially oil-wet, show large hysteresis between the advancing and receding angles. Due to the low solubility of the crude oil surfactants in the aqueous phase, the crude oil has to adhere to the surface before the surfactants, which promote oil wettability, can be adsorbed.

### **3.4 Low-salinity enhanced oil recovery**

The recovery of hydrocarbon fluid from subsurface formations is a complex process that associates multiple length scales. In typical water flooding process, seawater is injected on a macroscopic scale into the reservoir formation which carries hydrocarbon fluid (oil) to sweep the oil away from injection wells towards production wells. On the microscopic scale, the injected water displaces the oil in

the porous reservoir formation in a typical microfluidic two-phase flow of water and oil. Due to the large ratio of surface-to-volume, the efficiency of this process of microfluidic is strongly influenced by the surrounding porous rock matrix wettability. The rock formation ingredient, typically sandstone or limestone, is made of naturally hydrophilic material. Throughout millions of years of exposure to petroleum fluid, a layer of organic material adsorbed onto the surfaces and thus rendered the rock more hydrophobic. These molecular scale adsorption developments (as seen in **Figure 3**) thereby impede the oil displacement via water phase in the hydrophobized rock pores. This is understood to be one of the major causes why the secondary oil recovery is a rather inefficient process that leaves more than 50% of the oil unrecovered in the reservoir [26].

Since the 1970s, oil operator companies have examined several techniques to improve the low recovery rate by injecting various additives combined with the water aqueous phase. More recently, it was found that the recovery rate can be improved by desalinating the seawater before injecting it into the reservoir. The following sections will explore experiment and numerical developments of low water salinity approach.
