Experimental Investigation of the Effect of Injected Water Salinity on Oil Recovery and IFT Using Carbonate Rocks

Abstract – Low salinity water flooding is an emerging technology that can improve oil recovery. The attraction is due to its simplicity and relatively low cost. As a matter of fact, the incremental recoveries are in quite promising range of stock tank oil initially in place. Being a natural extension of the conventional water flooding, low salinity water flooding is easier to implement than any other enhanced oil recovery (EOR) methods. However, the processes of screening, designing, and implementing of this project require an increase operator capability and management focus compared to the conventional water flooding. The purpose of this work is to study the effect of injected water salinity during water-flooding on oil recovery and Interfacial Tension (IFT). The scope of work is achieved by conducting a series of core flooding experimental. Carbonate cores, different concentrations of water salinity, and oil samples of 30.4 API° are used to conduct the experiments. The study was further expanded to examine the heat effect by verifying temperature between 77 °F to 125 °F. The results showed that oil recovery was significantly increased to 26.47 % by low-salinity compared to higher salinity brine floods as a result of 11.47 % decrease in IFT.

Keywords: Oil Recovery, Salinity, Core Flooding

Dana Alkandari, Osamah Alomair, and Maqsood Iqbal
Petroleum Engineering Department, College of Engineering & Petroleum, Kuwait University


Water-flooding is the most applied method for recovering oil from the reservoirs. Different wetting states of crude oil, brine, and rock ensembles can yield widely different oil recoveries during laboratory waterflood tests (Jadhunandan and Morrow 1995). The wettability of a rock and fluids system can be altered in some ways: for example, changing crude oil composition, altering the aging temperature of the rock with crude oil, or by varying the temperature of displacement (Jadhunandan and Morrow 1995). The initial water saturation has a dominant effect on the wettability states induced by adsorption from crude oil because the distribution of water determines which parts of the rock surface are contacted by the oil (Salathiel 1973; Xie and Morrow 2001; Tong et al. 2002). Brine composition could have a significant impact on oil recovery (Yildiz et al., 1999; Tang and Morrow 1997). Low Salinity Flooding (LSF) is now recognized as an emerging technology in the water-flooding process. LSF into the reservoirs had been addressed since 1960s. Bernard (1967) documented that injection of fresh water both in secondary and tertiary modes could increase the oil recovery from sandstone cores containing clays. He also discussed permeability impairment and relatively high-pressure drops (Ali A. Yousef et al., 2011). Morrow et al., in 90’s conducted a first LSF detailed study as an EOR method (Yildiz and Morrow, 1996; Tang and Morrow, 1997). Later on, extensive research works have developed this idea into an emerged trend (Tang and Morrow, 2002; Zhang and Morrow, 2006; Zhang et al., 2007). Extensive research efforts had confirmed and validated the new trend conducting core-flood experiments (Webb et al., 2005; Lager et al., 2006 and 2007). Saudi Aramco has initiated a research program tagged “Smart Water-Flood” to explore the potential of increasing oil recovery by tuning the injection water properties such as; salinity, ionic composition, IFT, and viscosity (Ali A. Yousef et al., 2011). British Petroleum (BP) carried out a huge program on LSF and proposed additional recovery mechanisms (Mc Guire and Chatham, 2005; Lager et al. 2006). In recent years, using both laboratory and filed studies on mainly sandstones have shown that LSF has a significant impact on oil recovery (Ali A. Yousef et al., 2011). LSF has received growing attention over the past five years (Alotaibi and Nasr-El-Din, 2009; Lager et al., 2006, 2007 and 2008; Seccombe et al., 2008; Patil et al., 2008; Lebedeva et al., 2009; Ligthelm et al., 2009; Ashraf et al., 2010; Kumar et al., 2010).


The laboratory core-flooding experiments were performed on Carbonate core plugs prepared at Kuwait Institute for Scientific Research (KISR). Ten core samples were arranged for the tests and the range of Physical property is shown in Table 1. Crude oil sample of 30.4° API gravity was used to saturate the cores. Other fluid properties are measured at different temperatures at Petroleum Fluid Research Centre (PFRC) and tabulated in Table 2. Brine water was used as injected water and prepared with three different salinities of 800 ppm, 25,000 ppm and 100,000 ppm.


Coreflood Setup and Procedure

The Core-flood apparatus consists of a core holder, positive displacement pump, transfer vessels, and high-pressure steel piping. Water flooding is performed with a high pressure volumetric pump, connected to a tank containing distilled water. A cylinder is connected through a line to the inlet of the vacuum pump and to a graduated cylinder too, in order to measure recovery.

After cleaning the core holder, the core sample was placed inside a sleeve of rubber and set inside the core holder. The core is vacuumed by vacuum pump and a confining pressure (900 psi) around the sleeve is applied to prevent any leakage between the sleeve and the core inside. The core-flood experiments were performed at ambient temperature and pressure difference of 500 psi. This saturation process is done by gravity force to remove the possibility of air compressibility and it is accomplished by transferring the brine through a pipe which has a side connected to the inlet valve and the other side is inside a beaker filled with the brine. The pore volume is measured by subtracting brine inside beaker before and after opening of the inlet valve. To assure complete saturation, the core was flushed with brine at a flow rate of 0.35 cc/min. This is followed by an oil saturation process and that lasts until no more water is produced at an injection rate of 0.35 cc/min.

Then, the core was flooded with oil at an operating temperature of 25°C and a base absolute permeability was established within the core. The oil injection was continued until the injection pressure was stabilized. At this stage the core was at residual water saturation and saturated with oil such that the entire volume was occupied by injected oil. Then the prepared brine was injected into the same core to displace the oil. The laboratory prepared brine was injected at a rate of 0.35 cc/min into the respective core and then produced oil volume was measured. Though, we have tested ten samples as mentioned in Table 1, but finally only five (that have a variety of rock properties) were selected for the detailed analysis and discussion.

Interfacial Tension Measurement (IFT)

IFT between crude oil and brine as aqueous phase was measured by Pendent Drop IFT System. Equipment calibration test was performed with empty IFT cell. Injected laboratory prepared brines into the IFT cell to the full level. Reasonable temperature equilibrium inside the whole cell was achieved with an automated temperature control system. Keep on injecting the same brine into the cell in order to increase the inside cell pressure up to reservoir pressure level. Then, using the bottom needle, inject oil through to obtain a stable oil drop on the top of the needle inside the cell at required pressure (500 psi) and at both temperature (room, 25°C and elevated, 50°C) conditions. After adjusting the horizontal/vertical apex ratio and fixing the camera position took a picture. The complete shape of drop was analyzed with calibrated and accurate video lens system interfaced with drop shape analysis software. Then, the nonlinear system of differential equations was solved in Laplace Domain numerically over the complete shape of a drop. Repeat the same procedure with different brine salinities.


The experimental work was consisted of total six scenarios. Both room (25 °C) and 50 °C temperatures were investigated for Low Salinity Flooding (LSF, 800 ppm), Medium Salinity Flooding (MSF, 35,000 ppm) and High Salinity Flooding (HSF, 100,000 ppm). In this section, the impact of brine salinity upon recovery, IFT and rock properties will be discussed in details. Meanwhile, the temperature effect parallel to salinity will also be envisioned.

Salinity Impact on Recovery

In this section, the impact of injecting brine at both temperature conditions is visualized graphically for the best selected core sample. It is observed in Figure 1 that at 25 °C temperature, when the three salinity scenarios are plotted for the best core, low salinity (800 ppm) shows a relative increase in recovery for the same pore volume displaced. This proves that the salinity increase has a detrimental impact on reservoir properties. The sample for LSF is showing an increment of about 7.5 % in RF. Further, it can be concluded that even at high temperature and with the highest permeable core the RF for HSF case is still in the same range.

Oil Recovery

Fig. 1 Recovery Factor verses Injected Pore Volume (25° C)


Temperature Impact on Recovery

Both temperatures are investigated to visualize the effects on three salinity scenarios. Table 3 explains that a considerable temperature elevation effect on recovery is observed in case of LSF. More or less all samples exhibit the same trend of an increase in RF. However, the same increasing trend is observed in MSF but certainly it would have many detrimental salient features in it. Contrarily, HSF scenarios for all five samples show no improvement in RF as the result of temperature increase.

Table 3 Temperature Effect on Salinity


Salinity Impact on Interfacial Tension (IFT)

Low IFT is a favorable condition for an effective FOR technique. Several studies (Tang and Morrow, 1999; Lager et al., 2007; Seccombe et al., 2010; Yousef et al., 2010 & 2012) supported by pilot/field tests, suggest that additional oil can be recovered by reducing salinity. Various scenarios of salinity from low (800 ppm) to high (250000 ppm) are investigated for both room and elevated temperature with an IFT measuring device. The experimentally measured IFT is plotted in Figure 2. Overall, it can be seen that at low salinity the IFT is very favorable though a little impact of temperature increase is observed. Further, it can be perceived that an increase in temperature effect is considerable, for very high (100000 & 250000 ppm) salinity scenarios.


Fig. 2 Salinity Augments Interfacial Tension

Salinity Impact on Break Through (BT) Time and Water Cut (WC)

When BT time is plotted (Figure 3), at room temperature, it is observed that relatively a favorable, late BT time is observed when the injected brine is of medium or higher salinity. At some elevated temperature for the lowest salinity the same BT time is more delayed, whereas, in higher salinities the temperature effect is insignificant.

Core Flooding

Fig. 3 Break Through Time verses Salinity

When water cut (%) is plotted (Figure 4), at room temperature, it is observed that for low salinity brines water cut is relatively small Meanwhile it is also noted that more water cut is anticipated in MSF and HSF scenarios. Upon increase of temperature still the low ppm is more promising.


Figure 4 Water-Cut verses Salinity

Salinity Impact on Residual Oil Saturation

It is observed that salinity increase also disrupts the in-situ saturations conditions within the core. Table 4 shows best sample profile at both temperature conditions. It can be realized that residual oil saturation within the porous rock is more retained as more saline brine is injected. However, the residual oil saturation is further reduced at the same salinity values as the temperature is increased.

Oil Saturation

Table 4 Salinity Effects Residual Oil Saturation



1. The IFT and the injected brine salinity have a direct relationship.
2. The reduction in IFT leads to change the wetting conditions towards water-wet that is very favorable.
3. Rock properties, both permeability and porosity are badly impaired in case of HSF scenario.
4. An increase in oil recovery is observed for both room (25°C) and other (50°C) temperature water-floods. At
high temperature, this increase is more significant.
5. Breakthrough time can be increased and delayed water production by reducing the water injected salinity,
i.e., LSF scenario.


The authors would like to acknowledge the support of the General Facility Research Grants GE 01/07 (Petroleum Fluid Research Center – PFRC).


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