Efficiency of Ionic Liquids as an Enhanced Oil Recovery Chemical

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Efficiency of Ionic Liquids as an Enhanced Oil Recovery Chemical: Simulation Approach Mabkhot S. Bin Dahbag,† M. Enamul Hossain,*,†,‡ and Abdulrahman A. AlQuraishi§ †

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Department of Petroleum Engineering, College of Petroleum and Geosciences, King Fahad University of Petroleum and Minerals, Dhahran 31261, Saudi Arabia ‡ Department of Process Engineering (Oil and Gas Program), Memorial University of Newfoundland, St. John’s, Newfoundland A1B 3X8, Canada § National Center for Oil and Gas Technology, King Abdulaziz City for Science and Technology, Riyadh 11442, Saudi Arabia ABSTRACT: A significant portion of crude oil remains in the reservoir after the application of conventional recovery. To meet the growing demand of energy, enhanced oil recovery (EOR) methods should be used efficiently to recover the extra amount of trapped crude oil after secondary water flooding. Surfactant flooding is one of the chemical EOR methods that can be implemented to recover oil from the remaining oil in place. Ionic liquids (ILs), which are salts with a melting point beneath 100 °C, were considered as a prospective alternative to the surfactant because of their superiority in different points. In this paper, three flooding experiments using Berea sandstone samples were conducted using IL solution (commercially called Ammoeng 102) in different scenarios to check its recovery efficiency. In the first scenario, a core sample was saturated with crude oil up to irreducible water saturation (Swir) and then secondary flooded with brine. IL solution was followed in tertiary flooding mode. The second scenario was implemented by injecting a slug of IL solution [0.4 pore volume (PV)] chased with brine in the secondary flooding stage. Continuous secondary flooding with IL solution from the beginning to the end of experiment was used to carry out the third scenario. The experimental runs were simulated using the surfactant flood model (SFM) available in CMG STARS software. All three scenarios were successfully simulated, and a good match was obtained for oil recovery, well bottom-hole pressure, and imbibition relative permeability curves. Both simulation and experimental results proved the superiority of secondary continuous IL solution flooding, providing the highest oil recovery [71% original oil in place (OOIP)] compared to 64% OOIP for the secondary flooding of 0.4 PV IL solution slug. Tertiary IL solution flooding consequent to secondary water flood was able to recover 48% OOIP. Experimental contact angle measurements and the shift in relative permeability curves indicate that wettability alteration toward more water-wet characteristics is the main recovery mechanism for ionic liquid flooding.

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oborates [BF4]−, tetrachloroaluminate [AlCl4]−, and hexafluorophosphate [PF6]−, and (3) organic anions, such as methane sulfonate [R3C−S−O3]−, tosylate [C7H7O3S], and alkyl sulfate [R−O−SO3−]. Properties of ILs are controlled on the basis of the number of cations and anions used to form the IL molecule. They are considered as good candidates for many petrochemical industry applications.5,6 Among these are upgrading extra-heavy crude oil refining processes by cracking long asphaltene chains to smaller asphaltene chains.7,8 They can also be used in oil transportation to prevent asphaltene and paraffin aggregation inside pipelines. In addition, ILs can also be used to separate and desalt water and salts from oil−water emulsions.9 Inhibition of asphaltene precipitation in the reservoir during CO2 flooding is also an application investigated with promising results, indicating that less asphaltene deposition leads to the prevention of pore-plugging problems.10 ILs can also be used as a competitor to organic surfactants in demulsifying water−oil emulsion during the refining process.11 Recovery of heavy crude oil from tar sand using IL was investigated, and results

INTRODUCTION Enhanced oil recovery (EOR) is gaining more importance day by day as a result of the huge demand for crude oil. A large portion of the oil is left behind in the reservoir after traditional primary and secondary recovery methods. Many techniques were developed to recover that oil, and one of the most important EOR techniques is chemical flooding. Chemical EOR recovery mechanisms are either related to interfacial tension (IFT) reduction and wettability alteration using a surfactant or enhancement of sweep efficiency by controlling the oil−brine mobility ratio using polymers.1 Surfactants are known for their high toxicity and low efficiency in harsh environments of high salinity and high temperature. Ionic liquids (ILs), known as organic salts with a melting point less than 100 °C, can be a good alternative to conventional surfactants.2 They have many advantages over conventional surfactants, such as their friendly environmental impact, low cost, recyclability, non-corrosivity, stablilty, solubility in water and solvents, and their higher surface activity and ability to form a micelle in a harsh environment.3,4 ILs are classified into three categories based on molecule composition. These are (1) organic cations, such as alkyl phosphonium, alkyl sulfonium, N-dialkyl imidazolium, and thiazolium, (2) inorganic anions, such as halide, tetrafluor© 2016 American Chemical Society

Received: August 8, 2016 Revised: October 18, 2016 Published: October 21, 2016 9260

DOI: 10.1021/acs.energyfuels.6b01712 Energy Fuels 2016, 30, 9260−9265

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Energy & Fuels

conducted with secondary water flooding followed by tertiary continuous IL solution flooding. The second and third scenarios were conducted with IL solution in secondary injection mode with continuous IL solution in the third run and injection of 0.4 pore volume (PV) of IL solution followed by continuous chase water in the second run. More details on the core flooding unit, procedure followed, and discussion of results obtained are detailed in a previous publication.17 The following section will discuss the simulation outcomes in comparison to the experimental results. Simulation Runs. The core samples were modeled with a cuboidal shape instead of a cylindrical shape with equivalent volume and crosssectional area. The cuboidal was divided into 10 equal grids (Figure 1). Injection and production ports were placed in the first and tenth blocks, respectively. Reservoir properties, fluid properties, and wellbore characteristics were supplied in the software. Berea sandstone is known for its homogeneous characteristics; therefore, all grids were assigned the same porosity and permeability. The following discusses the simulation outcomes of the three flooding scenarios.

indicated a recovery as high as 90% original oil in place (OOIP) with 5 times IL recyclability and no efficiency loss.12,13 ILs have a high surface activity and tendency to form micelles.5,13,14 Hence, they can be used in EOR processes. Lately, efficiency of [C12mim][Cl] to minimize IFT with crude oil was investigated in harsh conditions of temperature and salinity.15,16 The obtained results indicate promising results for ionic solutions to recover trapped oil. Recently, several ILs were screened, and Ammoeng 102 was used in series of core flooding experiments of Berea sandstone cores at different flooding scenarios.17 The findings proved the effectiveness of ILs in secondary flooding mode and confirmed wettability alteration as the main recovery mechanism. This work is an extension of the previous work and aims at simulating the conducted core flood experiments using CMG STARS software to help model IL flooding performance on a field scale.

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RESULTS First Scenario. This run was conducted to simulate the first experiment. The sample grids were sized to 0.7285 cm in length, 3.2968 cm in width, and 3.2968 cm in height. The run was started at an initial oil saturation (Soi) of 0.7390 distributed uniformly. The sample was brine-flooded at 1 cm3/min in secondary flooding mode with 3 PV of brine injection. The tertiary mode was then commenced with 5 PV continuous IL solution injection. Oil saturation maps at the beginning of water flooding, end of secondary water flooding, and end of IL solution tertiary flooding are depicted in Figure 2. At the start of water flooding, the porous medium was uniformly saturated with crude oil. At the end of the secondary brine flooding, oil saturation was reduced to 0.4168. Clearly, it can be seen that crude oil was swept efficiently in a uniform manner as a result of the core sample homogeneity and continuous water flooding to 100% water cut. Tertiary IL solution flooding reduced residual oil saturation (Sor) in grids close to the production well. Figure 3 presents experimental and simulated oil recovery and well bottom-hole pressure of the first scenario. The simulation model indicates a total secondary recovery of 43% OOIP attained with early brine breakthrough occurring at 0.25 PV. Early breakthrough is attributed to the high mobility ratio as a result of the low brine viscosity compared to that of oil (1.27 cP compared to 5.50 cP). The model indicates an incremental tertiary recovery of 5% OOIP with tertiary IL solution injection. Clearly, these recovery values are equivalent

MATERIALS AND METHODS

Experimental Work. Brine solution of 20% (w/w) salinity consisting of 83.0% NaCl and 17% CaCl2 was used as formation water and to prepare the Ammoeng 102 IL solutions. The high salinity was chosen to simulate the Saudi reservoir formation brine. Tetraalkyl ammonium sulfate (known as Ammoeng 102) was the IL of choice based on the screening process of different ILs.18 On the basis of crude oil−IL solution IFT measurements, the IL concentration of 0.05 wt % was used providing an IFT of 2.14 mN/m. This concentration is a bit higher than the measured critical micelle concentration of 0.025 wt %. The oleic phase was Saudi medium crude oil [American Petroleum Institute (API) gravity of 28.37°] with 9.6% asphaltene content. Table 1 lists the physical properties of the fluids used at reservoir conditions of 60 °C temperature and 2000 psi pressure.

Table 1. Petrophysical Characteristics of Core Samples core 1 2 3

L (cm) D (cm) 7.28 6.35 6.50

3.72 3.74 3.79

pore volume (cm3)

Φ (%)

K (md)

Swirr

Sor

17.19 15.22 15.46

21.7 21.7 21.0

263 304 243

0.261 0.264 0.263

0.384 0.314 0.291

Three fresh Berea core samples were used to carry out the flooding experiments. Dimensions, porosity, absolute permeability, and end point saturations are listed in Table 1. Flooding runs were conducted at reservoir conditions of 60 °C temperature, 5000 psia overburden pressure, and 2000 psia pore pressure. Runs were conducted in three scenarios. The first was

Figure 1. Grid design of the core sample with injection and production wells. 9261

DOI: 10.1021/acs.energyfuels.6b01712 Energy Fuels 2016, 30, 9260−9265

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Figure 2. Oil saturation distribution.

was attained. Initial and final oil saturation maps are illustrated in Figure 5. Oil recovery and bottom-hole pressure in addition to secondary imbibition oil−water relative permeability curves are presented in Figures 6 and 7, respectively. Both figures present a close match between the simulation and experimental outcomes, with ultimate recovery of 64% OOIP. Third Scenario. This scenario was conducted on a model initially saturated with oil at 0.7370 with grids of 0.6500 cm length and width and height of 3.3588 cm. Similar to the second scenario, the model was flooded in secondary mode but with continuous IL solution. The flooding process was continued at 1 cm3/min with a total injection of 4.5 PV of IL solution. When oil recovery ceases, residual oil saturation was reduced to 0.2910. Figure 8 depicts the oil saturation maps before and after the IL solution flooding process. Figures 9 and 10 show a good match between the simulated and experimental outcomes of the third scenario, indicating an ultimate recovery of 71% OOIP.

Figure 3. Matching parameters between experimental and simulated runs of the first scenario.

to that obtained in the experimental work, as indicated by the excellent match attained during secondary brine and tertiary IL solution flooding. Experimental and simulated data of well bottom-hole pressure show some deviation from the experimental measurements during the secondary brine flooding. To be more familiar with this portion of flooding, measured imbibition oil−water relative permeability during secondary brine flooding was simulated and a fair match was attained, as seen in Figure 4.

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DISCUSSION In comparison of oil recovery findings of all scenarios, secondary continuous flooding with IL solution (third scenario) recovered 71% OOIP compared to 64% OOIP of secondary slug size flooding with IL solution (second scenario). Only 48% OOIP was recovered using tertiary IL solution flooding (first scenario). The lower oil recovery for the secondary slug size flooding compared to continuous flooding can be attributed to the possible dilution of IL solution with chased brine during the flooding process. The slug size used might not be the optimum size, and further runs need to be conducted to determine the optimum size to be implemented. The superiority of secondary flooding with IL solution in second and third scenarios over tertiary IL solution flooding presented in first scenario is attributed to the high rock water content characterizing the first scenario after secondary water flooding. As the water content reduces, IL solution efficiency increases, altering rock wettability to a more water-wet condition.17 A similar finding was obtained with surfactants in secondary and tertiary flooding modes.19 One of the most important advantages of both IL solution secondary flooding of second and third scenarios is the breakthrough delay to 0.48 PV compared to 0.25 PV for the brine secondary flooding conducted in the first scenario. This can be related to micelle formation, in which IL molecules aggregate together around small droplets of crude oil. These micelles behave like a polymer, improving the overall sweep efficiency. In addition, the IFT drop with IL can lower the capillary pressure and, consequently, improve the displacement efficiency.20−22 Well bottom-hole pressure increases at the breakthrough and starts to drop significantly immediately after breakthrough for all scenarios. This change is believed to be due to the possible formation of oil/water emulsion known for its high viscosity restricting water mobility through the oil

Figure 4. Relative permeability curves of the first scenario.

Second Scenario. This run was conducted on a model divided into 10 grids, 0.6354 cm long with width and height of 3.3189 cm at an initial crude oil saturation (Soi) of 0.7360 uniformly distributed. The sample was secondary flooded with a slug of 0.4 PV of IL solution at a rate of 1 cm3/min, chased with continuous 5.2 PV brine flooding. At the end of this process, a uniformly distributed residual oil saturation of 0.3140 9262

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Figure 5. Oil saturation distribution of the second scenario.

Figure 6. Matching parameters between experimental and simulated runs of the second scenario.

Figure 9. Matching parameters between experimental and simulated runs of the third scenario.

Figure 7. Relative permeability curves of the second scenario. Figure 10. Relative permeability curves of the third scenario. 23

phase, leading to pressure rise. Experimental and simulation relative permeability curves indicate a shift toward higher water

Figure 8. Oil saturation of the third scenario. 9263

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saturation, indicating some sort of wettability alteration toward a more water-wet state as we proceed from the first to second and finally third scenarios (Figures 4, 7, and 10). The effect of IL solution dilution in its efficiency as a wettability alteration agent was experimentaly proven by contact angle measurements in the presence of different IL concentratrions (Figure 11). As the concentration of IL increases, the contact angle

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AUTHOR INFORMATION

Corresponding Author

*Telephone: 00966-13-860-2305. Fax: 00966-13-8604777. Email: [email protected] and/or dr.mehossain@gmail. com. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors gratefully acknowledge King Abdulaziz City for Science and Technology (KACST) and King Fahad University of Petroleum and Minerals (KFUPM) for their financial and technical support.

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Figure 11. Contact angle of the oil droplet with the rock surface in the presence of different concentrations of IL solution.

decreases and wettability tends to shift toward a more waterwet characterstic. This study presents the success of the surfactant flood model (SFM) model in simulating the experimental outcomes of the IL flooding process and confirms the efficiency of IL solution as a replacement of toxic surfactant flooding during the chemical EOR process.

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CONCLUSION The SFM model available in CMG STARS simulator software was implemented to simulate IL solution flooding. Oil recovery, well bottom-hole pressure, and imbibition relative permeability curves were used as matching parameters. The results confirm the ability of the SFM model to simulate the process of IL flooding. The first experiment was conducted by injecting IL solution in tertiary flooding mode following conventional secondary water flooding. The model was capable of simulating the experimental findings, indicating 5% OOIP incremental tertiary recovery. The second experiment was carried out by flooding the core sample with 0.4 PV of IL solution chased with continuous brine injection in secondary mode. The model was again capable of simulating the experiment, and both indicated 16% OOIP incremental recovery over that obtained in the first scienario in tertiary flooding mode. Finally, the third run conducted in secondary continuous IL solution flooding mode was simulated, and outcomes indicate additional 7% OOIP recovery over that obtained from the second scenario of secondary 0.4 PV slug injection of IL solution. Imbibition relative permeability curves for the three runs were simulated, and a good match was obtained. Experimental and simulation relative permeability curves indicate a shift toward higher water saturation as we proceed from the first to second and finally third runs, indicating wettability alteration toward a more water-wet characteristic. This was proven experimentally using contact angle measurements, and clearly, wettability alteration is the main mechanism behind the incremental oil recovery. 9264

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DOI: 10.1021/acs.energyfuels.6b01712 Energy Fuels 2016, 30, 9260−9265