energies Article
CO2 Foam Stability Improvement Using Polyelectrolyte Complex Nanoparticles Prepared in Produced Water Negar Nazari, Jyun-Syung Tsau and Reza Barati * Chemical and Petroleum Engineering Department, University of Kansas, Lawrence, KS 66046, USA;
[email protected] (N.N.);
[email protected] (J.-S.T.) * Correspondence:
[email protected]; Tel.: +1-785-312-4442 Academic Editor: Dongsheng Wen Received: 31 January 2017; Accepted: 6 April 2017; Published: 11 April 2017
Abstract: Despite the increasing interest in CO2 foam flooding for enhanced oil recovery applications, it is challenging to have a successful field operation as the performance of the surfactant is often affected by the presence of crude oil and salinity of the water. It is also challenging to dispose of huge amounts of water associated with the field operation. Due to the incompatibility of the produced water with chemicals used in the foam system, the produced water cannot be used as an injecting fluid. The objective of this project is to design a chemical system compatible with produced water which may fully utilize the oil field produced water as an injecting fluid and make the foam injection economically viable and environmentally friendly. In this study, we investigate the performance of a foam system with a surfactant and the addition of polyelectrolyte and polyelectrolyte complex nanoparticles (PECNP) in various salinities of produced water. A recipe is developed to prepare a nanoparticle solution that is sustainable in high salinity produced water. The rheological property of the foam, the stability, and durability of the foam with and without the presence of crude oil are measured and compared as the water salinity is changed. It is found that foam stability and durability deteriorated when water salinity increased. However, by the addition of polyelectrolyte and PECNP in the system, the foam stability and durability was improved even in high salinity water with or without the presence of crude oil. Keywords: enhanced oil recovery; foam stability; CO2 foam; nanoparticles; produced water; critical micelles concentration; interfacial tension; polyelectrolyte complexes
1. Introduction The oil and gas industry has been using CO2 as an Enhanced Oil Recovery technique since the 1950s [1]. The potential of CO2 in contacting the bypassed area and reducing the trapped oil and its dynamic miscibility at lower temperatures compared to other gases has made it a good candidate for enhanced oil recovery applications. The high solubility of CO2 in the crude oil, for reservoirs which have a pressure above the minimum miscibility pressure of CO2 in oil, lowers the viscosity of the oil by 5–10 fold [2,3]. Due to the unfavorable mobility ratio of CO2 flooding, viscous fingering, gravity override, and poor sweep efficiency, several methods have been implemented to improve the usage of CO2 for enhanced oil recovery applications [4]. The alternate injection of water with CO2 , water alternating gas (WAG) process, and foam injection are the commonly applied methods to improve the mobility of CO2 in the displacement process. Although WAG alleviates the problem of the unfavorable mobility ratio between the displacing agent and the oil, while improving the vertical sweep efficiency in multi-layer reservoirs, it is reportedly damaging the injectivity of both water and CO2 [5]. On the other hand, foam is effective in reducing gas mobility in a broad range of rock permeability. Laboratory Energies 2017, 10, 516; doi:10.3390/en10040516
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and field observations seem to suggest a greater effect in high permeability zones when the tested porous medium is heterogeneous [6–8]. Foam is a special colloidal dispersion that consists of a gas, a liquid, and a foaming agent [9]. The quality of the foam is defined as the ratio of the gas volume to the total volume, and is between 60% and 90% for enhanced oil recovery applications. The effectiveness of surfactant generated CO2 foam very much depends on the surfactant characteristics [10]. The presence of crude oil affects the foam properties and destabilizes the foam by spreading the oil on the foam lamellae [11]. Moreover, the adsorption of the oil by the porous media changes the wettability of the rock and hardens the foam generation and degeneration [12]. Using nanoparticles as a stabilizer for the surfactant generated CO2 foam has been studied by other researchers [13]. Changing the concentration of the surfactants is assumed to affect the foam films and make the films more stable. However, using polyelectrolytes with opposite charges than the surfactant can be an alternative to the surfactant concentration changes [14]. Forming the polyelectrolyte/surfactant complexes in oppositely charged systems of surfactant and polyelectrolyte, also stabilizes the foam film by decreasing the surface elasticity [15]. Kalyanaraman et al. [13] developed a system of nanoparticles for stabilizing the foam in the presence of crude oil. They proved that their nanoparticle system had the capability of making foam more stable in low salinity systems of up to 2% KCl brine. Applying their nanoparticle system resulted in increasing the oil recovery and sweep efficiency of the reservoir. Large volumes of produced water from oil fields is a very important concern for the oil industry [16]. Disposal, treatment, and re-injection of the produced water are the available methods for handling the oil field produced water [17]. Water disposal is restrictedly controlled by environmental regulations. Since handling and treatment of the produced water increases operational costs and needs special equipment, re-injecting the produced water into the reservoir is the most optimized method to handle the produced water [18]. Re-injection of the produced water in enhanced oil recovery applications reduces the treatment difficulties while lowering the usage of fresh water in the oil industry. The main objective of this research is to stabilize the surfactant generated CO2 foam using polyelectrolyte complex nanoparticles (PECNP) in high salinity produced water and in the presence of crude oil. In this paper, the polyelectrolyte complex nanoparticle (PECNP) system with an optimized ratio of polyethylenimine to dextran sulfate was developed for different salinities. Particle size and zeta potential measurements were conducted and the most optimized ratios of polyelectrolyte to dextran sulfate were selected. Interfacial tension measurements were conducted to determine the critical micelles concentration (CMC) of the surfactant systems. Thereafter, the rheology of the different systems of CO2 foam was studied using an in-house foam rheometer. Finally, view cell tests were conducted to observe the supercritical CO2 foam stability and durability with and without the Mississippian crude oil in the system. 2. Materials 2.1. Polyethylenimine Polyethylenimine (PEI) or polyaziridine is a polymer with a repeating unit composed of an amine group and a two carbon aliphatic CH2 CH2 spacer. The PEI which has been used is the branched polycation and has a density of 1.03 g/mL at 25 degrees Celsius. It was purchased from Sigma Aldrich, St. Louis, MO, USA (Lot# MKBN3988V, CAS# 9002-98-6). 2.2. Dextran Sulfate The Dextran Sulfate (DS) that has been used is a polyanion and has an average molecular weight of 500,000. It also was purchased from Sigma Aldrich (Lot# 156852, CAS# 9011-18-1).
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2.3. Surfactant SURFONIC N-120 surfactant or Nonoxynol-12 is the 12-mole Ethoxylate of Nonylphenol. It is a water soluble, surface-active agent which is compatible with other nonionic surfactants and with most anionic and cationic surfactants. The company reported that this product is a nonionic surfactant, though our zeta potential measurements showed that it has an anionic nature with a tendency to adsorb to positively charged particles. The zeta potential for a 0.1 wt % surfactant solution in 33,667 and 67,333 ppm salinity of diluted Mississippian limestone play (MLP) brine was −1.16 and −12.29 mV, respectively, which shows the anionic nature of the surfactant. The theoretical molecular weight for this surfactant is 748 and the theoretical hydroxyl number is 75. This surfactant was provided by Huntsman chemicals, Woodlands, TX, USA (Lot# E312D33, CAS# 9016-45-9). 2.4. Mississippian Brine The formulation of a brine from the MLP brine sample was prepared in Deionized (DI) water and a synthetic brine was made based on that and was used for all the tests. The composition and related information of the salts in the brine are shown in Table 1. In order to obtain different salinities, the MLP brine was diluted using DI water in proper ratios. For example, in order to prepare the salinity of 33,667 ppm, the MLP brine was diluted six times and in order to prepare the salinity of 67,333 ppm, the MLP brine was diluted three times. Table 1. The final composition of the MLP brine. Brine Composition
Concentration (mg/L)
NaCl Na2 SO4 KCl MgCl2 ·6H2 O CaCl2 ·2H2 O SrCl2 ·6H2 O Total
163,661.82 1224.30 714.93 21,759.36 46,886.13 1535.5989 235,782.11
Provider
Lot#
CAS#
Location
Fisher Chemical Fisher Chemical AMRESCO Fisher Chemical Fisher Chemical Fisher Chemical
166221 134830A 1015C371 134660 159018 4AD13081428A
7647-14-5 7757-82-6 7447-40-7 7791-18-6 10035-04-8 10025-70-4
Lenexa, KS Solon, OH
2.5. Crude Oil Mississippian crude oil was used for the view cell experiments. The density and viscosity were measured to be 0.82 g/cc and 3.88 cP, respectively, at 40 degrees Celsius. The asphaltene content of this crude oil was measured to be approximately 0.5 wt %. 3. Sample Preparation 3.1. Surfactant Solutions The surfactant solution was prepared in two different salinities of 33,667 and 67,333 ppm. It was stirred for 30 min at 500 rpm. The final concentration of the surfactant in all the solutions was kept at 0.1 wt %. 3.2. Polyethylenimine Solution The PEI solution was prepared in two different salinities of MLP brine (33,667 and 67,333 ppm). It was stirred for 30 min at 500 rpm. The final concentration of the PEI in the solution was 1 wt %. A 600 mL sample of the PEI solution was prepared for each salinity. The pH of the solution was around 10 and it was lowered to 8 by adding 5.5 mL of 12N Hydrochloric acid (HCl).
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3.3. Dextran Sulfate Solution The DS solution was prepared in two different salinities of MLP brine (33,667 and 67,333 ppm). It was stirred for 30 min at 500 rpm. The final concentration of the DS in the solution was 1 wt %. 3.4. Nanoparticle Solutions For preparing the nanoparticle systems, different combinations of PEI:DS were prepared and the best ratio of PEI:DS was selected based on the zeta potential and particle size measurements, which are presented under the Results and Discussion section. In this study, four different ratios of 1, 2, 3, and 4 for PEI to DS were prepared and the ratio of 3:1:0.1 of PEI:DS:brine was selected. The sample was stirred for 30 min at 500 rpm. All the samples are presented in Tables 2 and 3. The nanoparticle solutions were prepared in the brine of up to 200,000 ppm salinity and they were stable in two ratios of 3:1:0.1 and 4:1:0.1 for PEI:DS:brine. The limiting factor for the experiments was the surfactant. 3.5. PEI-Surfactant and PECNP-Surfactant Systems After preparing the surfactant solution and the nanoparticle solution in any specific brine, the PEI:surfactant and the PECNP:surfactant systems were mixed in the ratios of 1:9 and 2:8 for the two different salinities of 33,667 and 67,333 ppm, respectively. Then the solutions were stirred for 30 min at 500 rpm. The final concentration of the surfactant in the solutions was kept at 0.1 wt %. 4. Methods 4.1. Zeta Potential and DLS Particle Size Measurements In order to select the best ratio of PEI:DS, the mean particle size and zeta potential were measured using a Brookhaven ZetaPALS instrument (Brookhaven Instruments Corporation, New York, NY, USA) which works based on Brownian movement. The Zeta potential or electrokinetic potential, which is a factor for determining the charge stability of the colloidal nanoparticles, is a measure of the effective electric charge on the nanoparticle surface. The potential difference between the bulk fluid in which the particles are dispersed and the layer of the fluid which contains the oppositely charged ions is determined as the zeta potential [19]. The magnitude of the zeta potential is a representative of the stability of the system. By increasing the zeta potential, the electrostatic repulsion and therefore, the stability of the nanoparticle system increases. Dynamic Light Scattering (DLS) has been used for measuring the diameter and the electrical double layer of nanoparticles. 4.2. Interfacial Tension Measurements Before preparing the samples, finding the critical micelle concentration (CMC) was the first step. All physio-chemical properties of a surfactant depend on the concentration of that surfactant, which means that if we plot them versus the concentration, there would be an abrupt change in the slope of the graph when micelles start to generate. After that sudden change, there is a plateau for all of the properties. That concentration is determined as the Critical Micelle Concentration (CMC) [20]. Keeping the concentration of the surfactant below the CMC is very important in order to preserve the surface activity of the surfactant. One method to find the CMC is to measure the Interfacial Tension (IFT) and plot it versus the surfactant concentration. For this experiment, the rising bubble method was used and the CMC has been found by plotting the IFT values versus the surfactant concentrations. The IFT decreases by increasing the surfactant concentration and the CMC is the point at which we reach a plateau in the graph. The CMC measurements will be shown in the Results section. A schematic diagram of this setup is presented in Figure 1.
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Figure 1. Schematic diagram theinterfacial interfacial tension tension measurement setup [13][13] (with permission from from Figure 1. Schematic diagram ofof the measurement setup (with permission Society of Petroleum Engineers, 2015). Society of Petroleum Engineers, 2015). Figure 1. Schematic diagram of the interfacial tension measurement setup [13] (with permission from
4.3. Society Rheology Measurements of Petroleum Engineers, 2015).
4.3. Rheology Measurements
The main purpose of the rheological measurements is to measure the bulk viscosity of different 4.3. Rheology Measurements The mainincluding purpose of the rheological measurements to measure the bulk viscosity of different samples the surfactant generated CO2 foam, is PEI-surfactant generated CO2 foam, and samples including the surfactant generated CO foam, PEI-surfactant generated CO foam, PECNP-surfactant generated CO 2 foam. The results of this study in the rheological measurement 2 2 The main purpose of the rheological measurements is to measure the bulk viscosity of different and section show theCO CO22 foam is The a shear fluid.study in generated PECNP-surfactant generated foam. results this the rheological measurement samples clearly including thethat surfactant generated CO 2 thinning foam,ofPEI-surfactant CO2 foam, and An Anton Paar rheometer was used for the rheological measurements. A schematic diagram section clearly show that the CO is The a shear thinning PECNP-surfactant generated CO 2 foam. results of this fluid. study in the rheological measurementof 2 foam this Anton setup isPaar shown in Figure 2. For these measurements, COmeasurements. 2 in the supercritical state was mixed section clearly show that the CO 2 foam is afor shear fluid. An rheometer was used thethinning rheological A schematic diagram of withAn the aqueous phase by passing it through a 7-micron inline cup has two Paar the rheological measurements. Ameasuring schematic state diagram this setup isAnton shown inrheometer Figure 2. was Forused theseformeasurements, CO2 mixer. in theThe supercritical wasofmixed co-axial cylinders. There is an annulus between them which was filled by the produced foam. Next, this setup is shown in Figure 2. For these measurements, CO 2 in the supercritical state was mixed with the aqueous phase by passing it through a 7-micron inline mixer. The measuring cup has two shear stress was applied on the outer cylinder, it was rotated, and the viscosity of that foam was with the aqueous phase by passing it through a 7-micron inline mixer. The measuring cup has two co-axial cylinders. There is an annulus between them which was filled by the produced foam. Next, determined. The pressure and temperature of the system was maintained at 1350 psi and 40 degrees co-axial cylinders. There is an annulus between them which was filled by the produced foam. Next, shearCelsius, stress respectively. was applied on the outer cylinder, it was rotated, and the viscosity of that foam was shear stress was applied on the outer cylinder, it was rotated, and the viscosity of that foam was
determined. The pressure ofthe thesystem system was maintained at 1350 psi40 and 40 degrees determined. The pressureand andtemperature temperature of was maintained at 1350 psi and degrees Celsius, respectively. Celsius, respectively.
Figure 2. Schematic diagram of the Anton Paar rheometer setup [13] (with permission from Society of Petroleum Engineers, 2015). Figure 2. Schematic diagram of the Anton Paar rheometer setup [13] (with permission from Society
Figure 2. Schematic diagram of the Anton Paar rheometer setup [13] (with permission from Society of of Petroleum Engineers, 2015). Petroleum Engineers, 2015).
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The The viscosity viscosity vs. vs. shear shear rate ratewas wasmonitored. monitored. After Afterfoam foamgeneration, generation, the the pumps pumps were were stopped stopped and and the the measuring measuring cup cup was was isolated isolated by by closing closing the the proper valves. The The measurement measurement was was continued continued by by conducting the shear ramp. In the ramp test, the foam was sheared with the shear rates reduced from conducting the shear ramp. In the ramp test, the foam was sheared with the shear rates reduced from 1 and 2000 then in in a reversed order forfor a total time of of 1515 min at at 3030 s intervals. 2000 ss−1−1toto100 100s−1s−and then a reversed order a total time min s intervals. 4.4. View View Cell Cell Testing Testing 4.4. The experimental experimental setup setup was was designed designed with with aa sapphire sapphire view view cell cell able able to to withstand withstand high high The temperatures and pressures. and durability of temperatures pressures. The The view viewcell cellsetup setupwas wasused usedtotodetermine determinethe thestability stability and durability thethe foam with and without thethe crude oiloil in in thethe system. AA schematic diagram forfor this setup is is shown in of foam with and without crude system. schematic diagram this setup shown Figure 3. 3. in Figure
Figure 3. 3. Schematic Schematic diagram diagram of from Society of Figure of the the Anton AntonPaar Paarrheometer rheometersetup setup[13] [13](with (withpermission permission from Society Petroleum Engineers, 2015). of Petroleum Engineers, 2015).
The first first series series of the experiments were performed without without any oil in the system. A A transfer transfer The cylinder was thethe aqueous phase which was the surfactant, PEI-surfactant, or PECNP-surfactant cylinder wasfilled filledbyby aqueous phase which was the surfactant, PEI-surfactant, or PECNPwhile a temperature controlled Teledyne ISCO pump ISCO was filled by was CO2 .filled Thenby by CO increasing surfactant while a temperature controlled Teledyne pump 2. Then the by temperature 40 degrees Celsius, the pressure 1350 reached psi. For 1350 generating the aqueous increasing thetotemperature to 40 degrees Celsius,reached the pressure psi. Forfoam, generating foam, phase and the supercritical CO2 were passed through a 7-micron inline mixer. Then viewThen cell was the aqueous phase and the supercritical CO2 were passed through a 7-micron inlinethe mixer. the filledcell by the foam and it was isolated monitor the decay time. versus time. view wasgenerated filled by the generated foam and it to was isolated tofoam monitor theversus foam decay The next next series series of of experiments experiments were were done done with with the the Mississippian Mississippian crude oil in the system. In In this this The series, after after filling filling the the view view cell cell by by the the generated generated foam, foam, the the oil oil was was introduced introduced into into the the view view cell, cell, series, displaced the the generated generated foam, foam, and and filled filled to to 25 25 percent percent of of the the view view cell’s cell’s length. length. Then Then the the foam foam decay decay displaced versus time time was monitored for all of our systems. versus
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5. Results and Discussion 5.1. Particle Size and Zeta Potential Results Tables 2 and 3 show the particle size and zeta potential measurements for different ratios of PEI:DS and PECNP:surfactant in two salinities of 33,667 and 67,333 ppm of diluted MLP brine, respectively. In both salinities, precipitations occurred with the ratios of 1:1:0.1 and 2:1:0.1 of PEI: DS: Brine. From Table 2, it can be observed that batch 1 gave the highest zeta potential values for the 33,667 ppm salinity of diluted MLP brine and was selected for continuing the tests. It can be seen that in 67,333 ppm salinity, batches 2 and 4 gave the highest zeta potential values (Table 3), and by considering the view cell testing results without the crude oil in the system, it was found that batch 4 performed better compared to batch 2 and it was selected for continuing the tests in this salinity. Note that the term “mobility” in these tables refers to electrophoretic mobility. Table 2. The summarized particle size and zeta potential values for different systems at 33,667 ppm of diluted MLP brine. The best system is highlighted.
Batch#
PEI:DS:Brine
PECNP:Surfactant
Final pH
Effective Diameter (nm)
Polydispersity
Zeta Potential (mV)
Mobility (µ/s)/(V/cm)
1 2 3 4 5 6 7 8 9 10
3:1:0.1 3:1:0.1 3:1:0.1 3:1:0.1 3:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1
1:9 2:8 3:7 4:6 5:5 1:9 2:8 3:7 4:6 5:5
7.91 7.93 7.94 7.94 7.90 7.85 7.92 7.96 7.97 8.00
108.93 ± 0.40 106.57 ± 1.50 102.74 ± 1.18 105.59 ± 1.87 106.99 ± 2.29 116.52 ± 2.14 110.32 ± 1.05 103.96 ± 1.42 107.94 ± 0.89 108.66 ± 4.76
0.27 0.24 0.25 0.25 0.25 0.26 0.26 0.25 0.25 0.24
21.18 ± 1.41 13.79 ± 2.99 15.30 ± 1.68 5.97 ± 5.04 11.00 ± 0.29 4.73 ± 1.04 14.93 ± 1.53 -
1.66 1.08 1.20 0.47 0.86 0.65 1.17 -
Table 3. The summarized particle size and zeta potential values for different systems at 67,333 ppm of diluted MLP brine. The best systems are highlighted.
Batch#
PEI:DS:Brine
PECNP:Surfactant
Final pH
Effective Diameter (nm)
Polydispersity
Zeta Potential (mV)
Mobility (µ/s)/(V/cm)
1 2 3 4 5 6 7 8 9 10
3:1:0.1 3:1:0.1 3:1:0.1 3:1:0.1 3:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1 4:1:0.1
1:9 2:8 3:7 4:6 5:5 1:9 2:8 3:7 4:6 5:5
8.08 8.18 8.12 8.15 8.25 8.01 8.21 8.15 8.15 8.27
114.00 ± 2.00 128.08 ± 1.26 128.98 ± 4.20 132.71 ± 3.13 120.71 ± 0.75 114.38 ± 3.15 103.84 ± 1.43 99.71 ± 1.11 107.10 ± 0.92 111.88 ± 6.47
0.268 0.300 0.319 0.311 0.283 0.264 0.265 0.261 0.273 0.286
9.81 ± 3.99 19.27 ± 0.63 13.49 ± 2.44 22.10 ± 0.34 17.66 ± 0.67 14.42 ± 2.66 11.82 ± 2.10 12.25 ± 3.15 16.31 ± 3.57 14.25 ± 4.36
0.77 1.51 1.05 1.84 1.38 1.13 0.92 0.96 1.27 1.11
5.2. Interfacial Tension Measurement Results The critical micelle concentration (CMC) was determined by plotting the interfacial tension (IFT) versus the surfactant concentration. Figures 4 and 5 show the interfacial tension plots versus the concentration of the surfactant for the two different salinities of 33,667 and 67,333 ppm of diluted MLP brine. It can be observed that the CMC is between 0.11 and 0.12. Therefore, the final concentration of 0.1 of the surfactant was chosen for all of the experiments.
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Figure 4. 4. Interfacialtension tension surfactant concentration for different systems in ppm 33,667 ppm Figure vs.vs. thethe surfactant concentration for different systems in 33,667 salinity Figure Interfacial 4. Interfacial tension vs. the surfactant concentration for different systems in 33,667 ppm salinity of diluted MLP brine. of diluted MLP brine. salinity of diluted MLP brine.
Figure 5. Interfacial tension vs. the surfactant concentration for different systems in 67,333 ppm Figure 5. vs.vs. thethe surfactant concentration for different systems in 67,333 salinity 5. Interfacial Interfacialtension tension surfactant concentration for different systems in ppm 67,333 ppm salinity of diluted MLP brine. of diluted brine. salinity of MLP diluted MLP brine.
5.3. Rheology Measurement Results 5.3. Rheology Measurement Results The nanoparticles have a small effect on the bulk viscosity and their major effect is on the surface The nanoparticles effect on on the the bulkbulk viscosity and their effect is on the nanoparticleshave havea asmall small effect viscosity and major their major effect is surface on the viscosity. viscosity. surface viscosity. In the ramp test, by using the power-law fluid model, which provides the relationship between the ramp test, byand using power-law fluid model, provides the relationship between theIneffective viscosity the the shear rate, the amount of the which flow consistency index (K) and the flow thebehavior effectiveindex viscosity and the shear rate, the amount of the flow consistency index (K) and the flow (n) were found. behavior index (n) were found. = ( ) n = (∂u ) τ ==K ( ( )) ∂y = ( )nfor −1 the three different systems of surfactant Figures 6 and 7 show the viscosity vs. rate µe fshear f = K (γ) generated 2 foam, PEI-surfactant generated 2 foam, andthree PECNP-surfactant generated CO2 Figures CO 6 and 7 show the viscosity vs. shearCO rate for the different systems of surfactant foam. Tables 4 and 5 show the computed flow consistencies and flow behavior indices for all the CO 2 generated CO2 foam, PEI-surfactant generated CO2 foam, and PECNP-surfactant generated CO 2
foam. Tables 4 and 5 show the computed flow consistencies and flow behavior indices for all the CO2
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Energies 2017, 2017, 10, 10, 516 516 of 15 15 Energies 99 of Figures 6 and 7 show the viscosity vs. shear rate for the three different systems of surfactant generated CO2 foam, PEI-surfactant generated CO2 foam, and PECNP-surfactant generated CO2 generated foam systems for thethe two different salinities of 33,667 33,667 and 67,333 ppmfor ofall diluted MLP foam. Tables 4 and 5for show computed flowsalinities consistencies and flow behavior indices the generated foam systems the two different of and 67,333 ppm of diluted MLP CO2 generatedBy foam systems forthe the two different salinities of 33,667 andthe 67,333 of diluted MLP by the brine, respectively. respectively. By comparing the values, it can can be found found that the COppm 2 foam generated brine, comparing values, it be that CO 2 foam generated by the brine, respectively. By comparing the values, it can be found that the CO foam generated by the highest 2 PECNP-surfactant shows shows the the most most optimized optimized results results in in the the lower lower salinity, salinity, since it it has has the the PECNP-surfactant since highest PECNP-surfactant shows the most optimized results in the lower salinity, since it has the highest consistency index and a low behavior index. However, the PECNP-surfactant generated CO foam consistency index index and aand low behavior index. the PECNP-surfactant generated CO22 foam consistency a low behavior index. However, However, the PECNP-surfactant generated CO2 foam improves the foam foam viscosity in the the higher salinity aswell. well. improves the in higher as well. improves the viscosity foam viscosity in the highersalinity salinity as
Figure 6. 6.Figure The viscosity viscosity vs. shear shear rate for for three different systems at 33,667 ppmsalinity salinity of diluted MLP MLP Figure The vs. rate different systems ppm salinity diluted 6. The viscosity vs. shear ratethree for three different systemsatat33,667 33,667 ppm ofof diluted brine. MLP brine. brine.
Figure 7. 7.Figure The viscosity viscosity vs. shear shear rate for for three different systems atat67,333 67,333 ppmsalinity salinity of diluted MLP MLP 7. The viscosity vs. shear ratethree for three different systemsat 67,333 ppm ofof diluted Figure The vs. rate different systems ppm salinity diluted brine. MLP brine. brine. Table 4. 4. The The flow flow consistency consistency and and flow flow behavior behavior indices indices which which have have been been calculated calculated by by using using the the Table power-law model model for for three three different different systems systems in in 33,667 33,667 ppm ppm salinity salinity of of diluted diluted MLP MLP brine. brine. power-law System System Surfactant Surfactant PEI-Surfactant, 1:9 1:9 PEI-Surfactant, PECNP-Surfactant, 1:9 PECNP-Surfactant, 1:9
K K 0.250 0.250 0.436 0.436 0.440 0.440
n n 0.520 0.520 0.520 0.520 0.520 0.520
0.99 0.99 0.99 0.99 0.99 0.99
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Table 4. The flow consistency and flow behavior indices which have been calculated by using the power-law model for three different systems in 33,667 ppm salinity of diluted MLP brine. System
K
n
R2
Surfactant PEI-Surfactant, 1:9 PECNP-Surfactant, 1:9
0.250 0.436 0.440
0.520 0.520 0.520
0.99 0.99 0.99
Table 5. The flow consistency and flow behavior indices which have been calculated by using the power-law model for three different systems in 67,333 ppm salinity of diluted MLP brine.
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System
K
n
R2
Surfactant PEI-Surfactant, 2:8 PECNP-Surfactant, 2:8
0.284 0.333 0.360
0.540 0.570 0.550
0.99 0.99 0.99
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5.4. View Cell Testing without Crude Oil 5.4. View Cell Testing without Crude Oil
In the view cell tests, the most optimized ratio of PECNP:surfactant was chosen by producing In monitoring the view cell tests, the most optimized PECNP:surfactant chosen producing foam and the foam decay time inratio an ofisolated view cell.was Figures 8 by and 9 show the foam and monitoring the foam decay time in an isolated view cell. Figures 8 and 9 show the comparison comparison for two different salinities of 33,667 and 67,333 ppm of diluted MLP brine. The ratio of for two different salinities of 33,667 and 67,333 ppm of diluted MLP brine. The ratio of 1:9 and the 1:9 and the ratio of 2:8 showed the most optimized performances in the two different salinities of ratio of 2:8 showed the most optimized performances in the two different salinities of 33,667 and 33,667 and 67,333 ppm of diluted MLP brine, respectively. Thereafter, the three CO2 foam systems, 67,333 ppm of diluted MLP brine, respectively. Thereafter, the three CO2 foam systems, surfactant, surfactant, PEI-surfactant, and PECNP-surfactant, were (Figures compared 10was andfound 11). Itthat wasthe found PEI-surfactant, and PECNP-surfactant, were compared 10 (Figures and 11). It that PECNP-surfactant the PECNP-surfactant generated COsystem 2 foam system showed the most optimized results in both generated CO2 foam showed the most optimized results in both salinities salinities of 33,667 and 67,333 ppm. Compared to the foam which is generated by theonly, surfactant of 33,667 and 67,333 ppm. Compared to the foam which is generated by the surfactant addingonly, adding PECNP the surfactant the foam bygenerates 100% and generates PEI PEI and and PECNP to theto surfactant solutionsolution improvesimproves the foam stability bystability 100% and a longer lasting foam,foam, resulting in a higher oil production. a longer lasting resulting in aamount higher of amount of oil production.
Figure 8. The foam decay thesurfactant surfactant different of PECNP:surfactant in 33,667 Figure 8. The foam decaytime time for for the andand different ratiosratios of PECNP:surfactant in 33,667 ppm diluted MLP brine. The The ratioratio of 1:9of shows the best result. ppmsalinity salinityofof diluted MLP brine. 1:9 shows the best result.
Figure 8. The foam decay time for the surfactant and different ratios of PECNP:surfactant in 33,667 11 of 16 ppm salinity of diluted MLP brine. The ratio of 1:9 shows the best result.
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Figure 9. The foam decay thesurfactant surfactant different of PECNP:surfactant in 67,333 Figure 9. The foam decaytime time for for the andand different ratiosratios of PECNP:surfactant in 67,333 ppm ppm salinity diluted MLP brine. 2:8 shows the best result. Energies 2017, 10, 516 11 of 15 salinity ofof diluted MLP brine. The The ratioratio of 2:8of shows the best result.
Figure 10. The foam decay time systemsofofgenerated generated 2 foam in 33,667 Figure 10. The foam decay timefor forthree three different different systems COCO in 33,667 ppmppm 2 foam salinity of diluted MLP brine without crude system.The The PECNP-surfactant shows shows the the best salinity of diluted MLP brine without crude oiloil in in thethe system. PECNP-surfactant best result. result.
Figure 10. The foam decay time for three different systems of generated CO2 foam in 33,667 ppm salinity of diluted MLP brine without crude oil in the system. The PECNP-surfactant shows the best Energies 2017, 10, 516 12 of 16 result.
Figure 11. The foam decay time systemsofofgenerated generated 2 foam in 67,333 Figure 11. The foam decay timefor forthree threedifferent different systems COCO in 67,333 ppmppm 2 foam salinity of diluted MLP brine without crude system.The The PECNP-surfactantshows shows the the best salinity of diluted MLP brine without crude oiloil in in thethe system. PECNP-surfactant best result. result.
5.5. View Testing with MississippianCrude Crude Oil 5.5. View Cell Cell Testing with thethe Mississippian Oil foam durability wastested tested by by the of of different CO2CO foam systems with the crude oil The The foam durability was theinteraction interaction different 2 foam systems with the crude and the results are shown in Figures 12 and 13. The interaction of different CO2 foam systems with the oil and the results are shown in Figures 12 and 13. The interaction of different CO2 foam systems with oil was recorded for the three different systems of surfactant, PEI-surfactant, and PECNP-surfactant the oil was recorded for the three different systems of surfactant, PEI-surfactant, and PECNPgenerated CO2 foam for the two different salinities. The PECNP-surfactant generated CO2 foam surfactant generated CO2 foam for the two different salinities. The PECNP-surfactant generated CO2 system was very stable in the presence of crude oil and at both water salinity systems tested in this foamwork. system waspolyelectrolyte very stable in the presence of crude and at both waterCO salinity systems tested in Using nanoparticles stabilizes theoil surfactant generated 2 foam and improves this the work. Using of polyelectrolyte stabilizes surfactant 2 foam durability the foam in the nanoparticles presence of crude oil in thethe reservoirs up togenerated 67,000 ppmCO salinity by and improves the durability of the foam in the presence of crude oil in the reservoirs up to 67,000 at least 100%, which results in higher oil recovery and improved sweep efficiency. It is shown inppm Figures 14least and 15 that the PECNP-surfactant generated CO2 foam a more stable front when it It is salinity by at 100%, which results in higher oil recovery andhas improved sweep efficiency. reaches the crude oil. This system works at 33,000 ppm salinity, which makes it a good candidate shown in Figures 14 and 15 that the PECNP-surfactant generated CO2 foam has a more stable front applications in offshore where they have ppm accesssalinity, to sea water. whenforit EOR reaches the crude oil. Thislocations, system works at 33,000 whichFurthermore, makes it a agood good portion of the conventional and unconventional resources in the United States produce brines candidate for EOR applications in offshore locations, where they have access to sea water. with salinities in the range of 67,000 ppm [21], and these results can be interpreted as a valuable opportunity, as the usage of produced water with significant concentrations of divalent cations is gaining more attention due to high ratios of produced water over crude oil in the United States and other oil producing countries of the world [22].
Furthermore, Furthermore, aa good good portion portion of of the the conventional conventional and and unconventional unconventional resources resources in in the the United United States States produce brines with salinities in the range of 67,000 ppm [21], and these results can be interpreted produce brines with salinities in the range of 67,000 ppm [21], and these results can be interpreted as as aa valuable opportunity, as the usage of produced water with significant concentrations of divalent valuable opportunity, as the usage of produced water with significant concentrations of divalent cations cations is is gaining gaining more more attention attention due due to to high high ratios ratios of of produced produced water water over over crude crude oil oil in in the the United United Energies 2017, 10, 516 13 of 16 States and other oil producing countries of the world [22]. States and other oil producing countries of the world [22].
Figure 12. Foam decay vs. time for systems generated 22 foam in Figure 12. 12. Foam decay vs.vs. time for three different systemsofof ofgenerated generated CO foam in 33,667 33,667 ppm Figure Foam decay time forthree threedifferent different systems COCO in 33,667 ppmppm 2 foam salinity of diluted MLP brine in the presence of Mississippian crude oil. The PECNP-surfactant system salinity of diluted MLP brine thepresence presenceof of Mississippian Mississippian crude The PECNP-surfactant system salinity of diluted MLP brine inin the crudeoil. oil. The PECNP-surfactant system shows the most durable foam system in the presence of crude oil. shows the most durable foam system in the presence of crude oil. shows the most durable foam system in the presence of crude oil.
Figure 13. Foam decay vs. time for systems generated 22 foam in Figure Foam decay time forthree threedifferent different systems COCO in 67,333 ppmppm Figure 13. 13. Foam decay vs.vs. time for three different systemsofof ofgenerated generated CO foam in 67,333 67,333 ppm 2 foam salinity of diluted MLP brine in the presence of Mississippian crude oil. The PECNP-surfactant system salinity of diluted MLP brine in the presence of Mississippian crude oil. The PECNP-surfactant system salinity of diluted MLP brine in the presence of Mississippian crude oil. The PECNP-surfactant system shows the most durable foam systemin the presence presence of shows the durable foam system of crude oil. shows the most most durable foam system ininthe the presence ofcrude crudeoil. oil.
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Figure 14. 14. CO CO22 foam foam generated by (a) surfactant and (b) PECNP-surfactant with with Mississippian Mississippian crude crude Figure generated by by (a) (a) surfactant surfactant and and (b) (b) PECNP-surfactant 2 foam generated oil after after 15 15 min min in in 33,667 33,667 ppm ppm salinity salinity of of diluted diluted MLP MLP brine. brine. oil
Figure 15. 15. CO CO22 foam foam generated by by (a) surfactant surfactant and (b) (b) PECNP-surfactant with with Mississippian crude crude Figure Figure 15. CO2 foam generated generated by (a) (a) surfactant and and (b) PECNP-surfactant PECNP-surfactant with Mississippian Mississippian crude oil after 55 min min in in 67,333 67,333 ppm ppm salinity salinity of of diluted diluted MLP MLP brine. brine. oil oil after after 5 min in 67,333 ppm salinity of diluted MLP brine.
Surfactant generated generated CO CO22 foam foam flooding flooding helped helped with with improving improving the the recovery recovery factor factor compared compared Surfactant Surfactant generated CO2 foam flooding helped with improving the recovery factor compared to CO 2 flooding, but the instability of the foam in the presence of crude oil is a limiting factor for for to CO2 flooding, but the instability of the foam in the presence of crude oil is a limiting factor to CO2 flooding, but the instability of the foam in the presence of crude oil is a limiting factor for using the the surfactant surfactant alone alone to to generate generate the the foam. foam. Adding Adding nanoparticles nanoparticles to to the the surfactant surfactant generated generated using using the surfactant alone to generate the foam. Adding nanoparticles to the surfactant generated CO 2 foam helps to improve the foam characteristics. The foam stability improves by strengthening CO2 foam helps to improve the foam characteristics. The foam stability improves by strengthening CO2 foam helps to improve the foam characteristics. The foam stability improves by strengthening the the foam foam lamella. lamella. Nanoparticles Nanoparticles line line up up and and charge charge the the foam foam interface. interface. Therefore, Therefore, bubbles bubbles with with the the the foam lamella. Nanoparticles line up and charge the foam interface. Therefore, bubbles with the same same charge charge repel repel each each other. other. This This helps helps to to thicken thicken the the lamella lamella and and prevents prevents foam foam coalescence. coalescence. same charge repel each other. This helps to thicken the lamella and prevents foam coalescence. Generating a Generating a stable foam in the presence of crude oil and in high salinity produced water can be be Generating a stable foam in the presence of crude oil and in high salinity produced water can achieved by by this this presented presented system. system. Improving Improving the the viscosity viscosity and and stabilizing stabilizing the the generated generated foam foam in in the the achieved
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stable foam in the presence of crude oil and in high salinity produced water can be achieved by this presented system. Improving the viscosity and stabilizing the generated foam in the presence of crude oil are the advantages of adding nanoparticles to the surfactant generated CO2 foam, which can result in increasing oil production and improving the sweep efficiency of the oil recovery process. 6. Conclusions The addition of PEI and PECNP to the surfactant for generating supercritical CO2 foam was investigated. After analyzing the results, the following conclusions are made: 1.
2.
3.
The rheology tests indicated that adding PEI and PECNP to the surfactant solution helps to improve the rheological properties of the foam. Under the ramp test, adding PEI and PECNP helped to improve both the flow consistency and behavior indices. The view cell test results without the crude oil showed that adding PEI and PECNP, in any ratio of PEI:surfactant and PECNP:surfactant to the surfactant solutions, improves the foam durability. Furthermore, the PECNP-surfactant generated CO2 foam showed the highest durability compared to the surfactant generated foam and the PEI-surfactant generated CO2 foam systems. From the view cell test results in the presence of the crude oil, it can be concluded that the PECNP-surfactant generated CO2 foam is more durable compared to the other two systems of the PEI-surfactant and surfactant generated CO2 foam. Additionally, the PECNP-surfactant generated CO2 foam stabilizes the interface of the foam when it reaches to the crude oil.
Acknowledgments: We would like to thank the Kansas Interdisciplinary Consortium Carbonates (KICC) and the NSF EPCoR for funding this project. In addition, the authors would like to thank Zach Kessler and Scott Ramskill from the Tertiary Oil Recovery Program (TORP) and the Chemical and Petroleum Engineering department at the University of Kansas for their kind help in installing the setups. Author Contributions: Negar Nazari helped with designing some of the experiments, performed all the experiments, analyzed the data, and wrote the paper. Jyun-Syung Tsau helped with designing some of the experiments, helped with the data analysis, and gave comments on the paper. Reza Barati, the PI of the project, contributed to the generation of the idea, designing of the experimental work, helped with analyzing the results, and modified the first draft of the paper several times. Conflicts of Interest: The authors declare no conflict of interest.
Nomenclatures τ K n µ µe f f γ
Shear stress, lb/ft2 Flow consistency index Flow behavior index Viscosity, cp Effective viscosity, cp Shear rate, s−1
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