Introduction

Ionic liquids (ILs) have received great environmental and technological attention as a potential alternative to traditional organic solvents. They are known as organic salts having a melting point below 100 °C (Xiao and Malhotra 2005), often found as liquids at ambient temperature (Domanska 2005; Simoni et al. 2008). Typically, ILs molecular composition consists of organic cations such as N-dialkylimidazolium, N-alkylpyridinium, alkylammonium, alkyl-phosphonium, alkylsulphonium and tiazolium; inorganic anions such as halide (e.g., Br−, Cl−), tetrachloroaluminate [AlCl4]−, tetrafluorborate [BF4]−, hexafluorphosphate [PF6]−, bis(trifluoro-methyl-sulfonyl)imide [(CF3SO2)2N−] and acetate [CH3CO2 −] and organic anions such as alkylsulfate [R-O-SO3−], tosylate [C7H7O3S] and methanesulfonate [R3C-S-O3-]. ILs are known for their negligible vapor pressure and non-flammability under ambient conditions, high thermal conductivity, high polarity, high heat capacity, high density, extremely low volatility and thermal stability (Domanska 2005; Siedlecka et al. 2011; Keith and Johnson 2007; Bermudez et al. 2009). They have many advantages over organic surfactants. Among these advantages are their low cost and commercial availability, water and solvents stability, low toxicity, in addition to their noncorrosive properties and recyclability (Domanska 2005; Dharaskar 2012). The most important attribute of ILs is their potential as tunable solvents with properties that can be tailored according to their application based on their number of cations and anions combination (Siedlecka et al. 2011; Hernández et al. 2011).

ILs were used in petroleum industry to upgrade heavy and extra heavy crude oil by cracking asphaltene chains (Fan et al. 2007, 2009. They are also used to inhibit paraffin and asphaltene aggregation and precipitations in addition to desalting and demulsifying of water in oil emulsions in refining process (Lemos et al. 2010). The role of ILs in inhibiting asphaltene precipitation in simulated CO2 flooding was investigated (Hu et al. 2004). Minor asphaltene precipitation and deposition were reported in the presence of IL preventing pore plugging problems during flooding process. ILs can replace organic surfactant in breaking water/oil emulsions in oil refining process (Lucero et al. 2010). The self-organization, micelle formation and surface properties of ILs (Hernández et al. 2011, 2009) as well as their ability to dehydrate crude oil have been recently reported (Painter et al. 2010). Lately, the efficiency of ILs in extracting heavy oil from tar sands was evaluated (Painter et al. 2009; Hezave et al. 2013a). Recovery efficiency of 90 % was reported with five times ILs recyclability with no efficiency loss.

The increased demand for energy directed the oil industry to explore different enhanced oil recovery methods to release the trapped oil left behind at the end of the primary injection. Among the EOR methods is the chemical flooding and among these chemicals are the surface acting agents (surfactants). Lowering the aqueous-oleic pair interfacial tension (IFT) and wettability alteration due to adsorption are the main recovery mechanisms for organic surfactant flooding. ILs are known for their surface activity and micelle formation; therefore, they can be of potential for flooding process. The effect of ([C12 mim] [Cl]) ionic liquid on interfacial tension in harsh environment (high salinity, high temperature) was investigated to assess its efficiency for chemical flooding Hezave et al. (2013b; Somasundaran and Zhang 2006). Findings indicate promising results demonstrating the effectiveness of ionic solutions as EOR chemical for enhanced recovery of trapped oil.

This work is aimed at screening different ILs based on their solubility in different brine compositions, thermal stability and ability to significantly lower the IFT at high salinity and temperature conditions. The most efficient ionic liquid is further tested in several flooding runs at reservoir conditions to investigate its adsorption tendency and its efficiency as new enhanced oil recovery chemical.

Materials and methods

Materials

Fresh Berea sandstone samples were used for the different flooding runs. Routine core analysis was conducted on the tested samples and their petrophysical properties are listed in Table 1. X-ray diffraction analysis (XRD) shown in Fig. 1 indicates that rock mineralogy is composed mainly of Quartz with Kaolinite clay as cementing material. Aqueous phase used in screening process was distilled water and three synthetic brine solutions at 10 % (w/w) salinity listed as brine I (100 % NaCl), brine II (95 % NaCl, 17 % CaCl2) and brine III (83 % NaCl and 17 % CaCl2). Brine III at 10 and 20 % (w/w) salinity was used as aqueous phase in further investigations such as CMC determination, adsorption and flooding process. Ionic solutions were prepared by diluting ILs with the brine composition and salinities indicated above.

Table 1 The petrophysical properties of core samples
Full size table
Fig. 1
figure 1

XRD analysis of berea sandstone core sample

Full size image

Oleic phase was Saudi medium crude oil. Analysis of crude asphaltene content indicated the presence of aromatic hydrocarbon compounds (cyclic) with saturated carbon chains characterized with average length of six carbon atoms (five CH2 and one CH3). Small sample of asphaltene was tested with Carbon/Hydrogen/Nitrogen Analyzer implementing the ASTM D5291 method. The measured crude oil properties are listed in Table 2.

Table 2 Physical properties of crude oil
Full size table

Nine ionic liquids listed in Table 3 were screened. These ILs were prepared at different concentrations in different brine solutions of different compositions at 10 % (w/w) salinity. Screening process was based on ILs solubility in brine solutions and their surface activity, in addition to their thermal stability (no turbidity) at wide temperature ranges. The determined most effective ionic solution (tetra alkyl ammonium sulfate known as Ammoeng 102) was further investigated by testing its surface activity at various conditions of pressure, temperature and solution salinity. IFT investigation of crude oil-Ammoeng 102 solution was conducted at different concentrations ranging from 0 to 2,000 ppm. The Ammoeng 102 solutions were prepared in synthetic formation brine at 10 and 20 % (w/w) salinities at reservoir conditions of 60 °C and 2,000 psig.

Table 3 Summary of ionic liquids screening results
Full size table

IFT measurements

IFT measurements were conducted using high-pressure and high-temperature pendant drop tensiometer (Fig. 2). The tensiometer is composed of high-pressure cell, hand pump for fluids displacement, vibration-free table, needle, temperature controller, pressure transducer, back pressure regulator, lamb, digital camera supplied with video frame grabber for image display and analysis system using Young–Laplace equation. IFT is measured by upward injection of drop of oil to the tip of proper size needle immersed in brine or ionic solutions.

Fig. 2
figure 2

Pendant drop tensiometer and contact angle setup

Full size image

Wettability measurements

Contact angle between crude oil and Ammoeng 102 solutions on rock surface was measured using pendant drop setup described above with some modification. The measurements were conducted at reservoir condition of 60 °C and 2,000 psig. Different concentrations (0, 250, 500 and 1,000 ppm) of Ammoeng 102 diluted in synthetic brine III solution at 20 % (w/w) salinity were tested. Thin smoothed surface sample of Berea sandstone rock was placed horizontally in the high-pressure cell and surrounded by ionic solution. Pressure and temperature were set and small oil drop was released using the needle to the bottom of the rock surface. Several pictures were captured and the contact angle was measured.

Adsorption measurements

Adsorption is the adhesion of atoms, ions, or molecules on solid surfaces. Adsorption is affected by several factors and among these are the chemical structure of the liquid (i.e., ionic liquid), rock surface properties and mineralogical composition, composition of reservoir fluids, and solution conditions such as salinity, pH, pressure and temperature (Hurd and Research 1976; Bai et al. 2010). Adsorption mechanisms are classified into electrostatic attraction/repulsion, ion exchange, chemisorption, chain–chain interactions, hydrogen and hydrophobic bonding (Hurd and Research 1976).

Dynamic Adsorption of 500 ppm Ammoeng 102 solutions at 10 and 20 % (w/w) salinities was measured in two core samples representing the investigated porous medium. 100 cm3 of ionic solution was continuously injected at 1 cm3/min under reservoir conditions of 60 °C temperature and 5,000 and 2,000 psig confining and pore pressures, respectively. The effluent fractions were collected in 10 cm3 tubes and analyzed using Ultra Violet Spectrophotometry to determine the IL adsorption.

Core flooding

Flooding was conducted using automated core flooding system (Fig. 3). It consists of a core holder capable of housing 1.5 in. diameter and up to 6 in. long sample. The setup is equipped with three transfer accumulators for crude oil, brine and ionic solution. Constant flow positive displacement pump is used to inject distilled water to the bottom of the three accumulators to transfer the content fluids as needed. Fluids are directed via a network of steel pipelines and air operated shut off valves. The overall components are incorporated in air-circulating oven for temperature control. Confining pressure is controlled by automated pressure intensifier while pore pressure is controlled via dome type backpressure regulator. Effluents produced are collected in graduated tubes placed in timely set fraction collector. Inlet, outlet pressures and pressure drop across the core are measured by high precision line and differential transducers. All components and measurements are controlled and collected continuously by data acquisition system.

Fig. 3
figure 3

Schematic of core flooding setup

Full size image

The test started with core sample evacuated and pressure saturated with the desired brine solution. The fully brine saturated sample was then flooded with brine at different rates to record the corresponding pressure drops to determine rock absolute permeability utilizing Darcy law. Drainage cycle was started by oil displacement at 1 cm3/min. Oil injection continued until water production ceases and irreducible water and initial oil saturations are determined using material balance. Brine and/or ionic solution flooding were conducted in secondary and/or tertiary modes and oil recovery and end point saturations were determined. Unsteady state method was used to calculate the imbibition relative permeability curves of the secondary flooding portion of the experiments implementing Jhonson–Bosler–Numan (JBN) method. Flooding process was conducted at reservoir conditions of 5,000 and 2,000 psig confining and pore pressures, respectively, and temperature of 60 °C. Rapoport and Leas (1953) indicated that Displacement is independent of length (L), displacing fluid viscosity (μ) and injection velocity (V) when laboratory scaling coefficient (LVμ) is within the range of 0.4–5.0. The Rapoport and Leas scaling rule was used to ensure the displacement stability of conducted experiments and a value of 2.5 was found.

Results and discussion

Screening process

General screening of nine ionic liquids was conducted. The screening was conducted on ionic solutions of different ILs concentrations ranging from 100 to 1,000 ppm diluted in distilled water and different synthetic brines. The brines were of various salt (NaCl and CaCl2) contents as indicated previously at 10 % (w/w) salinity. Tests were conducted at atmospheric pressure and different temperatures ranging from 22 to 90 °C. Screening criteria were based on ionic liquids solubility in distilled water and different brines, surface activity, and solutions thermal stability (no turbidity) at high temperatures. Table 3 lists the ionic liquids tested and summarizes the major outcomes of the screening process. Ammoeng 111 and Ammoeng 130 were excluded due to their insolubility in all aqueous solutions. Ammoeng 111 is characterized with very long cationic chain length, while Ammoeng 130 is characterized as non-polar with long chain length of ethyl group and that may explain their insolubility. The rest of ionic liquids have different degree of solubility and they were screened based on their surface activity and IFT trend with temperature. Ammoeng 102 ionic solution provides the lowest IFT with decreasing IFT trend with temperature. Ammoeng 110 has a similar IFT trend with temperature but with less surface activity. Longer alkyl chain length of the Ammoeng 102 cation tends to increase its capability of reducing IFT and may explain its superior surface activity (Smit et al. 1990; Hezave et al. 2013c). Thermal stability of Ammoeng 102 maintains up to 81 °C above which, the ionic solution started to darken with full turbidity noticed at 86 °C and above. Figure 4 shows pictures taken for oil drop in 500 ppm ionic solution at temperatures ranging from 82 to 86 °C indicating the turbidity progress.

Fig. 4
figure 4

Turbidity of 500 ppm Ammoeng 102 diluted in Brine III at 20 % (w/w) Salinity

Full size image

Accordingly, Ammoeng 102 was the ionic liquid of choice soluble in all aqueous phases tested with significant surface activity at increasing temperatures. Further investigation of Ammoeng 102 was conducted on Ammoeng 102 surface activity at reservoir conditions of pressure and temperature. The investigation was conducted on crude oil and ionic solutions prepared at 10 and 20 % (w/w) salinity. Figure 5 plots the IFT versus ionic liquid concentration at both solution salinities. The plots indicate IFT declines with the increasing IL concentration. In contrast to conventional organic surfactants, the decreases are more pronounced at higher solution salinity. This can be attributed to the role of negatively charged ions neutralizing the positive surface charges of the cationic ionic liquid leading to easier accumulation of IL molecules at the oil–brine interface, and hence more IFT reduction Hezave et al. (2013c). Critical Micelle concentration (CMC) was achieved at low concentration of 250 ppm for both salinities with IFT of 3.36 and 1.65 mN/m for 10 and 20 % (w/w) solutions salinity, respectively. A concentration of 500 ppm was decided to be the ionic liquid concentration used for flooding runs.

Fig. 5
figure 5

IFT of Ammoeng 102 at different concentrations diluted in Brine III (83 % NaCl, 17 % CaCl2) at 10 and 20 % (w/w) Salinities at 60 °C and 2,000 psig

Full size image

The effects of temperature and pressure on Ammoeng 102 solution-crude oil IFT at 10 % (w/w) solution salinity were investigated and Figs. 6, 7 are plots of IFT trends at different temperatures and pressures, respectively. The results indicate a decreasing trend of IFT with increasing temperature at constant pressure and a slight increase with increasing pressure at constant temperature. Effect of temperature on IFT can be described based on two competing factors. The first is the adsorption of IL into the interface leading to lower IFT while the second is diffusion of the adsorbed IL into the oil phase leading to emulsion inversion and reverse effect of temperature on IFT. Similar trends are expected for Ammoeng 102 solution at 20 % (w/w) salinity but with lower IFT values. The ability of ionic liquid to tolerate high salinity, temperature and pressure in addition to its effectiveness in reducing interfacial tension at such conditions indicates the potential of these liquids over organic surfactants for EOR processes in harsh reservoir conditions.

Fig. 6
figure 6

Effect of Temperature on IFT of 500 ppm Ammoeng 102 Diluted in Brine III (83 % NaCl, 17 % CaCl2) at 10 % (w/w) Salinity

Full size image
Fig. 7
figure 7

Effect of Pressure on IFT of 500 ppm Ammoeng 102 Diluted in Brine III (83 % NaCl, 17 % CaCl2) at 10 % (w/w) Salinity

Full size image

Adsorption

Adsorption of 500 ppm Ammoeng 102 ionic solutions at 10 and 20 % (w/w) solution salinity was studied on two fresh Berea core plugs (plugs 5 and 6) with petrophysical properties listed in Table 1. Figure 8 plots the adsorption as a function of ionic solution pore volumes injected. The figure indicates high adsorption for both solutions with more adsorption for higher salinity one.

Fig. 8
figure 8

Adsorption of 500 ppm Ammoeng 102 Diluted in Brine III (83 % NaCl, 17 % CaCl2) at 10 and 20 % (w/w) Salinity

Full size image

The high adsorption level can be attributed to the high specific surface area characterizing the Kaolinite clay in addition to the strong electrostatic interaction between the negative charge at the kaolinite surface and the opposite cationic charge of the Ammonium cations (Song et al. 1994; Lv et al. 2011). Adsorption is expected to decrease in the presence of oil and formation brine which can limit the accessibility of ionic liquid molecules to rock grain surfaces Hezave et al. (2013b).

Flooding runs

A series of flooding runs on fresh cores were conducted at reservoir conditions. Figure 9 plots the recovery curves for three runs with irreducible water saturation (S wirr) of 26 %. All runs were conducted with synthetic formation brine, injected brine and ionic solution all at 20 % (w/w) salinity. The first run was started with secondary brine flooding to residual oil saturation (S or) followed by tertiary flooding of ionic solution. Second run was conducted in secondary mode where a slug of 0.4 pore volume of ionic solution was injected into core sample at initial oil saturation (S oi) followed by continuous brine injection at the same salinity. Third run was conducted in secondary mode but with continuous ionic solution injection. The results indicate an incremental tertiary oil recovery of 5 % original oil in place (OOIP) over that obtained by secondary brine injection (43 % OOIP) corresponding to 8 % residual oil in place (ROIP). Secondary ionic solution flooding runs provided a much higher ultimate recovery of 63 and 70 % OOIP for slug and continuous ionic solution injection, respectively, indicating the efficiency of ionic solution injection in secondary mode at initial oil saturation. The higher ultimate recovery for the secondary ionic solution flooding can be attributed to the lower water content of the sample rocks and hence the less dilution of the ionic solution within the porous medium. At low water content, ionic solution is more effective in lowering the interfacial tension and altering rock wettability to more water wet characteristic.

Fig. 9
figure 9

Effect of injection mode on recovery curves

Full size image

Wettability alteration and IFT reduction are the main mechanisms in chemical EOR. IFT value as low as 0.01 mN/m is needed to mobilize significant residual oil indicating stronger role for wettability when IFT is not drastically low (Song et al. 1994). To investigate the wettability alteration, contact angel measurements were conducted at reservoir conditions in the presence of 20 % salinity ionic solutions at different concentrations (0, 250, 500 and 1,000 ppm). Figure 10 shows oil drops shapes in the presence of different ionic solution concentrations indicating the decrease of contact angle with the increasing ionic liquid concentration. The decreasing trend of contact angle indicates wettability alteration from slightly oil wet condition to medium water wet condition. Relative permeability curves constructed for the above runs (Fig. 11) indicate increasing rock water wetness, higher oil relative permeability (K ro) and lower S or as we proceed from secondary brine flooding to continuous secondary ionic solution flooding.

Fig. 10
figure 10

Relative permeability curves of secondary flooding runs

Full size image
Fig. 11
figure 11

Contact angle measurements at different Ammoeng 102 concentrations

Full size image

To further investigate the effect of rock water content on ionic solution recovery efficiency, one more run (run 4) was conducted in tertiary injection mode but at higher S wirr of 34 %. Figure 12 plots the recovery curve for this run in comparison to run 1 conducted at S wirr of 26 %. Higher recovery was obtained in the secondary brine flooding stage for low S wirr run with 44 % OOIP compared to 38 % OOIP for high S wirr run. Tertiary recovery with ionic solution was slightly higher (6 % OOIP) for low S wirr run compared to that of high S wirr run (4 % OOIP). This corresponds to 8 and 9.4 % ROIP, respectively. The higher secondary recovery for low S wirr run can be attributed to the presence of higher amount of recoverable oil and less water content compared to high S wirr case. At the end of the secondary flooding, the water content for both rocks was very close and hence water content effect on tertiary cycle of both runs was minimized as indicated by the close tertiary recovery factors. Table 4 summarizes the outputs of the conducted runs listing the recoveries and the end point saturations and relative permeability’s.

Fig. 12
figure 12

Effect of irreducible water saturation on recovery curves

Full size image
Table 4 Recovery factors and flooding parameters
Full size table

Conclusions

This study aimed at investigating the efficiency of ILs for chemical EOR. The work started by screening several ILs based on their solubility in brines, surface activity, and the solutions stability at high temperatures. Based on the screening process, Ammoeng 102 was the ionic liquid of choice. Reservoir condition measurements of Ammoeng 102 solutions-crude oil IFT at different IL concentrations and solutions salinities indicate significant IFT reduction with increasing concentration for both salinities with more IFT reduction at higher solution salinity. Low CMC values of 250 ppm were obtained for both solution salinities. Temperature and pressure have low effects on IFT measurements within the ranges investigated. Ammoeng 102 adsorption on rock surface at reservoir conditions indicates high tendency for adsorption with more adsorption noticed for higher salinity ionic solution.

A series of flooding runs on fresh Berea cores demonstrate the effectiveness of Ammoeng 102 ionic solution, especially when injected in secondary mode at S wirr either as a slug followed with brine or continuous injection. Relative permeability curves indicate increasing rock water wetness, higher K ro and lower S or as we proceed from secondary brine flooding to secondary slug of ionic solution flooding to secondary continuous ionic solution flooding. Wettability alteration was confirmed by contact angel measurements demonstrating rock wettability shift from slightly oil wet to medium water wet condition as we increase the IL concentration in the aqueous phase. The effect of rock water content (S wirr) on ionic solution recovery efficiency showed higher oil recovery for secondary brine and tertiary ionic solution flooding at low S wirr indicating the role of formation and rock water content in ionic solution effectiveness. It is worth mentioning that wettability is very much affected by rock mineralogy and rock type, hence the results obtained and presented are limited to the rock type investigated. Currently, we are investigating different sandstone and carbonate samples and so far promising preliminary results were obtained and more work is undergoing.