Application of Organic Alkali for Heavy-Oil Enhanced Oil Recovery ...

Article pubs.acs.org/EF

Application of Organic Alkali for Heavy-Oil Enhanced Oil Recovery (EOR), in Comparison with Inorganic Alkali Donghai Xie,*,† Jirui Hou,† Ankit Doda,‡ and Japan Trivedi‡ †

Enhanced Oil Recovery Institute, China University of Petroleum, Beijing 102249, China School of Mining and Petroleum, University of Alberta, Edmonton, Alberta, Canada T6G 2W2

‡

ABSTRACT: Alkali is an important component for alkali/surfactant/polymer technology for enhanced oil recovery (EOR). The mechanism and advantages of traditional inorganic alkali for EOR was reviewed in this paper. The rheological and dynamic properties of the combination of alkali and polymer were analyzed. The results show that the polymer solution with ethanolamine has better shear viscosity and elastic properties at room temperature. Surfactant (Alfaterra 123-8S-90) with concentration of 0.15 wt % was added into each alkali−polymer (AP) solution. No significant change was observed in rheological properties of AP solutions with and without surfactant. Emulsification tests show that ethanolamine has better performance with oil. Injectivity tests were also conducted. The results indicated that the residual resistance factor (RRF) for an ethanolamine− polymer solution is always higher at each flow rate tested, in comparison to a NaOH-based AP solution, which is beneficial for oil recovery. The interfacial tension (IFT) tests results indicated that ethanolamine has better synergy with the surfactant. Polymer adsorption using both static and dynamic measurements was conducted. Polymer solution in an ethanolamine system has lower adsorption for both measurements. The pressure comparison during core flooding experiments shows that it has higher injection pressure in ethanolamine conditions, which result in good sweep efficiency. The ethanolamine−polymer flooding showed a significant increase in oil recovery (15.33%) over NaOH−polymer flooding. After the addition of surfactant, the total recovery improves by 14.8% for ethanolamine−polymer−surfactant flooding over its inorganic counterpart. The better performance indicates that ethanolamine can become a potential alkali and can replace NaOH for EOR.

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finished in February 1997 and the subsequent water flooding was started. Up to August 1998, the oil recovery was increased by 18.5% and the water cut was decreased to 85.6% for the central well group.11 Although the AP flooding technology has good performance under field conditions and at laboratory scale, some problems with this have been reported. The alkali in the AP solution can react with divalent ion and rock mineral (kaolinite, feldspar, montmorillonite) in reservoir to produce precipitates, which can block the reservoir pores and therefore affect the production capability, damaging the lifting system and shortening the average pump-checking cycle accordingly.12−16 Alkali−surfactant−polymer (ASP) is a promising method, because it has the synergy of alkali, surfactant, and polymer. In an ASP process, alkali, surfactant and polymer are added in the same solution slug. However, it also has scaling problems. The scaling problems in an oilfield in Alberta was discussed by Arensdorf et al.17 After the ASP flood was started, the wellhead was covered with silicate scale one month later. The average well run time was just 3.8 months, and it increased to 13.2 months with inhibitor application. The pilot test of strong ASP flooding in North-1 East zone had similar problems. Even the scale prevention was taken and the average pump-checking period was extended from 120 days to 162 days; however, it was still 50% shorter than that in the case of polymer flooding.18 Another side effect of alkali is the negative influence

INTRODUCTION Heavy oil reservoirs with viscosities of >1000 cP are being exploited using chemical enhanced oil recovery (EOR) processes. Polymers represent the most widely used chemical for these operations to recover oil. Polymer increases the viscosity of injected solution and improves the mobility ratio in the reservoir that results in improved sweep efficiency.1 Also, it is believed that the polymer viscoelastic property is beneficial to reduce the residual oil saturation.2−6 Polymer also can be used with other chemicals such as alkali and surfactant for EOR. When alkali is used with polymer, it can react with acid component in crude oil to form surfactant, which can reduce the interfacial tension (IFT) between oil and water.7 In addition, there are other mechanisms by which alkali improves the oil recovery, such as emulsification and entrainment, emulsification and entrapment, and wettability reversal. The mechanism of the alkali−polymer (AP) flooding has been discussed in previous studies by other researchers.8,9 There are numerous successful experiences using AP flooding. An AP flood was implemented in the center of David Field (now called Black Creek), outside of Lloydminster, Alberta, Canada. Average production by water flooding was 53.9% OOIP. Injection of the AP solution produced 21% OOIP additional oil beyond that producible by water flooding and the total recovery was 73%.10 A pilot test of AP flooding was conducted in the west area of the fault block of the XingLongTai oil field. The central well group had three injection wells and one production well. The injection of a slug of 0.35 PV of AP solutions started in January 1995 when the oil recovery was 46.75% and the water cut was 96.1%. This process © 2016 American Chemical Society

Received: February 16, 2016 Revised: April 30, 2016 Published: May 19, 2016 4583

DOI: 10.1021/acs.energyfuels.6b00363 Energy Fuels 2016, 30, 4583−4595

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Energy & Fuels

conditions were compared. IFT and polymer adsorption between ethanolamine and NaOH conditions were also compared. Finally, the core flooding experiments were conducted to investigate the performance of ethanolamine on EOR, comparing with NaOH at the same residual oil saturation.

on the rheology properties of polymer solution. The research performed by Hou et al.19 indicated that both the loss modulus and storage modulus of polymer solution decreased proportionally with the increased alkali concentration. The ability of polymer solution sweeping residual oil in blind spots increased when the alkali concentration decreased. The work done by Kazempour et al.20 also indicated that alkali significantly increases the ionic strength of ASP solution, which results in the low viscosity. Although NaOH and Na2CO3 are popularly used as alkali for AP solution, it is necessary to find other alternatives for alkali, which can reduce the disadvantages and replace the traditional alkali. Berger and Lee21 used an organic alkali for EOR to pair it with the polymer. The results showed that organic alkali does not precipitate with divalent cations and performed equally in softened as well as unsoftened brine. This may reduce up-front costs of water treatment, handling, and disposal. Meanwhile, organic alkali was as effective as inorganic alkali in obtaining low IFT. Wang et al.22 also compared sodium carbonate and organic alkali NPS-2 with concentrations in the range of 0.10%−1.50%. The aqueous solution of sodium carbonate had no emulsification with oil, while there was significant emulsification for the organic alkali solution when the concentration was above 0.30%. Higher emulsification directly relates to improved oil recovery, so using organic alkali can be a good alternative for EOR. Zhao et al.23 performed a series of experiments on emulsification performance of organic alkali by testing the dehydration rate. They compared ethanolamine and sodium carbonate for emulsification performance by syneresis rate. The syneresis rate is defined as the rate of water drainage from emulsion. The size of emulsified oil droplets were larger and the maximum syneresis rate was 68% when used with ethanolamine, which was 33% higher, compared to sodium carbonate solution. Li et al.24 investigated the performance of three types of organic alkali (methylamine, trimethylamine, triethylamine) on IFT. The results showed that, when only organic alkali or surfactant were used, they produced high IFT, while the combination solutions of organic alkali and surfactant (even in low concentration) showed synergism and therefore had low IFT. Guerra et al.25 performed the displacement experiments using the organic alkali as alkaline component in ASP solution. Three tests were conducted with permeabilities from 811.26 mD to 1186.9 mD. The ASP solution was injected after water flooding, and the additional recovery for ASP flooding was from 21.05% to 23.33%. Wang et al.22 conducted a more-detailed analysis on this theory. They compared the additional recovery of different aqueous solutions involving polymer and alkali. The value for this additional recovery was 13.71% for polymer flooding, 13.64% for polymer and inorganic alkali (sodium carbonate) flooding, and 24.69% for polymer and organic alkali (NPS-2). It showed that organic alkali has much better performance in flooding experiments. As the performance of organic alkali in all these aspects mentioned above, it is important to investigate another organic alkali for use in EOR to strengthen this concept. Therefore, in this study, ethanolamine (organic alkali) was compared with NaOH (inorganic alkali) for AP and ASP flooding. Hydrolyzed polyacrylamide (HPAM) polymer was used to prepare AP solutions and Alfoterra 123-8S-90 surfactant for APS solutions. Test procedures were established to compare the performance of different chemical solutions with ethanolamine and NaOH, based on rheological properties. The injectivity properties between ethanolamine and NaOH

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EXPERIMENTAL SECTION

Materials and Method of Solution Preparation. The polymer used in this study is FLOPAAM 3130s, which was supplied by SNF SAS in dry powder form. FLOPAAM 3130s is an anionic and watersoluble hydrolyzed polyacralymide (HPAM) polymer with a degree of hydrolysis of 25−30 mol % and an average molecular weight of 2 000 000 Da. Crude oil was collected from a heavy oil reservoir in north-central Alberta. Basic sediment and water from the crude oil was removed by high-speed centrifugation, as well as gravity segregation. The measured oil viscosity was ∼550 cP at 25 °C. Oil viscosity was checked using rheometer (described later) each time before the experiment to maintain the consistency. NaOH with a purity of ∼98.5%, which was used as inorganic alkali, was supplied by ACROS. Ethanolamine (∼99% pure) was used as organic alkali supplied by Sigma−Aldrich. Deionized (DI) water was used for all the experiments. The polymer solutions (0.1 wt % concentration) were prepared by adding them to DI water. Powders were added with constant stirring and were maintained at 350 rpm using a magnetic stirrer. The concentration of alkali (NaOH, ethanolamine) used was varied from 0 to 1 wt %, at intervals of 0.25 wt %. Surfactant was used with a concentration of 0.15 wt %. Proper care was taken to ensure that polymers are not added too rapidly in order to avoid lumping of the powder. The solution was stirred for ∼2 h until it became completely transparent and no filtration was needed. Rheological Experiments. Viscoelasticity measurements were carried out by a C-VOR 150 Peltier Bohlin rheometer (Malvern Instruments, USA) with a cone and plate measuring system and strain model measurements at 25 °C. Polymer samples were placed between a stationary plate with a diameter of 60 mm and a rotating upper cone with a 4° angle and a diameter of 40 mm, separated by a gap of 150 μm. Viscometry and oscillation tests were performed to compare shear viscosity and elastic properties (loss and storage modulus) for the sample solutions. Viscometry Tests. Viscometry tests were carried out at shear rates varying from 1 s−1 to 100 s−1. Shear viscosity was plotted as a function of shear rate for polymer samples in both alkaline and nonalkaline conditions. Oscillation Tests. Frequency tests were carried out on polymer samples at a frequency range of 0.01−1 Hz, keeping the stress value constant at 0.04775 Pa. Oscillatory measurements provide the absolute values of the complex modulus |G*|, the storage modulus or elastic modulus G′, and the loss modulus or viscous modulus G″, at a constant frequency and constant strain. These magnitudes of frequency and strain were chosen to provide a stress of reasonable magnitude for the purpose of sensitivity. Injectivity Experiments. To analyze the effect of porous media, we performed the injectivity tests. Experimental procedure for the injectivity test is as follows: Primary Water Injection (Permeability Calculation). Water was injected into the core at constant flow rates of 0.5, 1.0, 2.0, 3.0, and 4.0 mL/min, and the differential pressure was recorded. Water was flushed until the differential pressure stabilized. Polymer Solution Injection (Resistance Factor Calculation). Then, the water was displaced with the chemical solution (polymer (P) or alkali−polymer (AP)). The flow rates used for the polymer/AP solutions were the same as that for water injection. Here, differential pressure was also recorded. Stable differential pressures were achieved for each flow rate. Post-Water Injection (Residual Resistance Factor Calculation). Water was injected using the same flow rates as the primary water 4584


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Figure 1. Schematic of core experimental setup. where co is the polymer concentration of influent, cl is the polymer concentration of effluent, mo the weight of polymer solution of injection, ml the weight of effluent, and ms the weight of the sand. Interfacial Tension (IFT) Test. The Model SVT 20N spinning drop tensiometer, produced by Dataphysics Corporation (Germany), was used to measure interfacial tension (IFT). Chemical solution and crude oil was injected into the sample cell. The sample cell then was placed into the SVT 20N spinning drop apparatus at 25 °C. The oil droplet was stretched in chemical solution until IFT reached equilibrium at the rotation speed of 5000 rpm. The test time was no less than 2 h. The image of oil droplet was stored every minute. In each image, the height and length were measured and then the IFT was calculated by the software of the tensiometer itself. The SVT 20N spinning drop tensiometer is a special-purpose optical instrument for measuring high to extremely low IFT values. The control software is designed for easy use and fast access to all control elements. The speed range is 0 to 20 000 rpm and the temperature range is −10 °C to 130 °C. The IFT can be measured over a range of 10−6 to 2000 mN/m. Core Flooding Experiments. A cylindrical horizontal core holder (1 1/4 in. diameter, 6 in. length) was used for flooding experiments. Perforated screens at either end of the core were used as injector and producer. Glass beads used in core flooding experiments were of 325 mesh size with a particle size distribution of 30−50 μm, supplied by Potters Industries LLC. For each test, fresh glass beads were packed to ensure the same wettability. The core was packed dry, using a mallet as well as a pneumatic vibrator ensuring a tight packing. Pore volume (PV) of the porous medium was measured using a direct method. The volume of glass beads in the cylindrical core was subtracted from the bulk volume of the core. A specific gravity of 2.5 was used to calculate the volume of glass beads in the model for each experiment, using the known mass that was required for packing. The ISCO Model 500D syringe pump was used to saturate the core with heavy oil. Oil was injected using a piston-based accumulator at constant pressure to avoid leakage during oil injection. A schematic of experimental setup is shown in Figure 1. All of the experiments were performed with the model in a horizontal position. Therefore, the gravity was assumed to have no influence in the observations of the experiments. The pressure drop across the core was recorded using a pressure transducer that had a full-scale limit of 2500 psig (Omegadyne, Inc.). The core flooding experiments were performed by the following procedure:

injection, and the differential pressure was noted. Until a constant differential pressure was attained, water was injected at each flow rate. Emulsification Test. The alkali used for emulsification tests were NaOH and ethanolamine, respectively. The concentrations were 0, 0.25 wt %, 0.50 wt %, 0.75 wt %, and 1.0 wt %. Oil and different concentrations of alkali in 10 mL cylinders were mixed and shaken for a while. Pictures then were taken at times t = 0, 5 min, 15 min, 30 min, and 60 min. Adsorption Experiments. Adsorption experiments were conducted through static and dynamic adsorption, respectively, to indicate the influence of alkali on polymer adsorption. Static Adsorption. Static adsorption is done in polyethylene bottles with tight polypropylene lids. Sand and chemical solutions are mixed in the bottles with a certain ratio. The bottles are placed into a mechanical shaker and agitated continuously for a specific time. After adsorption, the samples are removed and centrifuged. Then, the supernatant solutions are separated by decantation from the vial of the solids after gravity sedimentation. The supernatant solutions will be used to measure polymer concentrations using the Starch−Cadmium Iodine Method.26 The polymer adsorption can be calculated as polymer adsorption =

(co − ca) × ml ms

(1)

where co and ca are polymer concentrations before and after static adsorption, respectively, and ml and ms are the mass of solution and sand, respectively. Dynamic Adsorption. First of all, permeability test for core will be conducted at five different flow rates (2, 3, 4, 5, and 6 mL/min). The procedure of dynamic adsorption experiment is described as follows: (1) Chemical flooding will be conducted until pressure reaches equilibrium. It means the adsorption reaches equilibrium and the concentration of polymer in effluent should be same with or at least close to influent. In this experiment, 2 PV chemical solution will be injected. (2) Water flooding will be injected until the concentration of polymer is too low to measure. In this experiment, 3 PV water will be injected. (3) Repeat step 1. (4) Repeat step 2. The flow rate during flooding is 2 mL/min. The weight of sand and effluent will be measured. The polymer concentration in the effluent will be measured by spectrophotometer. Adsorption of polymer on sand can be calculated as follows:

adsorption (mg/g) =

(co × mo) − (cl × ml ) × 1000 ms

• Initially core was prepared as described in aforementioned section and the effective porosity of the core was calculated. • The core was flooded with water to establish connate water saturation and permeability was measured by varying the flow rate between 2 mL/min to 6 mL/min and recording the pressure drop along the core.

(2) 4585


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Figure 2. Shear viscosity versus shear rate: alkali−polymer (AP) solution viscosity at different NaOH concentrations (the polymer concentration is 0.1 wt %).

Figure 3. Shear viscosity versuss shear rate: alkali−polymer (AP) solution viscosity at different ethanolamine concentrations (the polymer concentration is 0.1 wt %). • The core was then flooded with the crude oil at constant pressure; the effluents were collected to obtain initial water and oil saturations in the core through material balance. • After saturation, core was flooded with 1.5 PV of water, displacing oil to establish residual oil saturation. • For tertiary recovery, AP or ASP solution was injected for 1 PV. • At the end, 1.5 PV of water was injected at the same flow rate. Flow rates for waterflood and chemical flood were held constant at 0.5 mL/min. Volumes of effluent from producer were collected at regular intervals.

However, for ethanolamine solution, this ratio is close to 2−3. The shear viscosity for AP solutions with ethanolamine is in the range of 0.01−0.1 Pa s, which is higher than the shear viscosity for AP solutions with NaOH (ranges between 0.001 Pa s and 0.01 Pa s). This shows that, in the presence of ethanolamine, the shear viscosity performance of the polymer is better than that of the NaOH−polymer solution. The addition of alkali increases the pH and ionic strength. The pH increase rises the degree of hydrolysis, which results in more negative charge on the polymer chains; hence the polymer molecules are more expansive to obtain higher viscosity. On the other hand, the increase of ionic strength shields the negative charges on the polymer chains, which reduces the repulsive forces between ionized carboxylic groups. Therefore, the polymer chains coil to become more compact, resulting in a smaller viscosity.27−29 Improved shear viscosity performance of HPAM, in the presence of ethanolamine, can be explained by using the pH and ionic strength measurements for AP solution stated in Table 1. These measurements shows that the pH of the ethanolamine−polymer solution is always less than its NaOH counterpart for each concentration. By increasing the concentration of alkali from 0.25 wt % to 1 wt % (both NaOH and ethanolamine), the pH value does not change significantly but the ionic strength of the solution changes significantly instead. Strong alkali can shield the charge on HPAM polymer chains, which aids them to stretch in an

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RESULTS AND DISCUSSION Shear Viscosity Analysis. Figures 2 and 3 show the shear viscosity of polymer solution with different concentrations of NaOH and ethanolamine, respectively, at room temperature. The concentrations of alkali vary from 0 to 1 wt %. For both alkali systems, shear viscosity decreases as shear rate increases, exhibiting a shear-thinning behavior similar to pure polymer solution. This phenomenon can be related to the breakage of polymer chains when exposed to high shear flow. In addition, the shear viscosity shows a decrease with increasing alkali concentration, as a result of the alkali shielding the charge on polymer chains. Shear viscosity of pure HPAM polymer solution is always higher than that of AP solution for both alkalis for all shear rate data points. For pure HPAM solution, the shear viscosity is almost 10-fold, compared to that of HPAM−NaOH solution for different alkali concentrations. 4586


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solutions in ethanolamine and NaOH are shown in Figures 7 and 8, respectively. The polymer solution without alkali has a larger elastic modulus than that of AP solutions. The elastic modulus decreases significantly with a small quantity of alkali (NaOH or ethanolamine). The elastic modulus of AP solutions with NaOH as well as ethanolamine does not vary significantly as the alkali concentration increases from 0.25 wt %. Both AP solutions have similar elastic moduli at 0.25 and 1 wt %. It suggests that both of NaOH and ethanolamine have a negative influence on the elastic modulus of polymer solutions. The viscous modulus of AP solutions decreases with the alkali concentration. The ethanolamine systems have larger viscous moduli than NaOH solutions. The surfactant Alfaterra 123-8S-90 was added into the AP solutions to form ASP solutions. The elastic and viscous modulus are shown in Figures 9 and 10, for NaOH and ethanolamine, respectively. The ASP solutions with both types of alkali have similar viscous and elastic profiles to those of the respective AP solutions, which indicates that the addition of surfactant has no significant influence on the dynamic viscoelastic behaviors. Injectivity Analysis. To analyze the effect of AP solutions on porous media, the resistance factor (RF) and the residual resistance factor (RRF) were tested. RF is a measurement of the decrease in the mobility of chemical solution, in comparison to that of injection water. RRF represents the ability of a polymer solution to decrease reservoir permeability and is defined as the ratio of the permeability to brine before and after the injection of chemical solution. When RF and RRF values for different flow rates were compared for both ethanolamine and NaOH with polymer solution (see Tables 2 and 3), the RF and RRF values for ethanolamine−polymer solution is always higher than the NaOH−polymer solution at each flow rate tested. This suggests that the decrease in permeability due to HPAM−ethanolamine solution is higher than that due to the NaOH−HPAM solution, which can lead to flow diversion of AP solution or postwaterflood solution to uninvaded parts of the reservoir and therefore improve the sweep efficiency. The high RF and RRF factors, because of the high amount of adsorption, can raise injectivity issues (i.e., plugging), where an exponential increase in the pressure of the reservoir is observed. However, the issue of injectivity is debatable, because no injectivity problems were seen for practical application in oil fields. The formation of a gel

Table 1. pH and Ionic Strength for Different Concentrations of AP Blends Alkali Concentration (wt %)

Measured pH

Calculated Ionic Strength

NaOH

ethanolamine

NaOH

ethanolamine

NaOH

ethanolamine

0.25 0.5 0.75 1

0.25 0.5 0.75 1

12.12 12.2 12.22 12.23

10.89 11.05 11.12 11.2

0.0625 0.125 0.1875 0.25

0.041 0.082 0.123 0.164

aqueous solution, because of the high value of ionic strength (large number of ions in aqueous solution), as seen in the case of NaOH. In this regard, the ethanolamine solution, even at high concentration, has pH and ionic strength values at which the HPAM shear viscosity does not decrease much, compared to pure HPAM solution. Improved viscosity compliments the resistance factor (RF) comparison for both AP solutions in the absence of oil (see Table 2, presented later in this work). The RF value for the ethanolamine−polymer solution is higher at each tested flow rate, compared to that of NaOH−polymer solution, which shows lower mobility for organic alkali−polymer solution, compared to inorganic alkali−polymer solution. The surfactant with a concentration of 0.15 wt % was added into each AP solution to form the ASP solution. Figures 4 and 5 show the shear viscosity of ASP solutions with different NaOH and ethanolamine concentrations, respectively. It was observed that the ASP solutions have the similar viscosity performance as the AP solutions, indicating that the addition of surfactant has no significant effect on the shear viscosity of the polymer. Figure 6 shows the shear viscosity of AP and ASP solutions at shear rates of 10, 30, and 40 s−1, respectively. At each shear rate, the shear viscosity of each solution decreases as the alkali concentration increases. The shear viscosity is reduced sharply when the concentration changes from 0 wt % to 0.25 wt %. The addition of surfactant has no significant effect on the shear viscosity. This suggests that the shear viscosity of polymer solution is sensitive to alkali, which is more pronounced from zero to small concentrations and then becomes stagnant. Also, for each shear rate, the shear viscosity of ethanolamine−HPAM solution is higher than that of NaOH−HPAM solution. Dynamic Viscoelastic Behaviors. The comparative variation of elastic modulus and viscous modulus for AP

Figure 4. Shear viscosity versus shear rate: alkali−surfactant−polymer (APS) solution viscosity at different NaOH concentrations (the polymer concentration is 0.1 wt % and the surfactant concentration is 0.15 wt %). 4587


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Figure 5. Shear viscosity versus shear rate: alkali−surfactant−polymer (APS) solution viscosity at different ethanolamine concentrations (the polymer concentration is 0.1 wt % and the surfactant concentration is 0.15 wt %).

Figure 6. Effect of NaOH and ethanolamine concentration on shear viscosity of AP and ASP solution with different shear rates.

layer, on the injection side, was observed only below a critical threshold permeability and pore throat radius.30 Static Adsorption Experiment. The static polymer adsorption results are shown in Figure 11. The amount of polymer adsorption decreases as the alkali concentration

increases from 0 to 0.5 wt %, then increases when the alkali concentration is higher than 0.75 wt %. This is due to the changes in pH and ionic strength, which are induced by increases in alkali concentration. As discussed above, the high pH results in more-expansive polymer molecules; hence, the 4588


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Figure 7. Elastic and viscous modulus versus frequency: AP blend elastic and viscous moduli at different NaOH concentrations (the polymer concentration is 0.1 wt %).

Figure 8. Elastic and viscous modulus versus frequency: AP blend elastic and viscous moduli at different ethanolamine concentrations (the polymer concentration is 0.1 wt %).

adsorption. However, ionic strength is the determinant at high concentration. As discussed in the shear viscosity session above, the ionic strength of NaOH-based solution is significantly higher than that of the ethanolamine system. Therefore, ionic strength has more outstanding effect than pH between these two alkalis. Because of its higher ionic strength, the NaOH system has higher adsorption. The effect of reaction time on polymer adsorption is shown in Figure 12. In AP solutions, the adsorption has no significant difference between NaOH and ethanolamine solutions before 12 h. After reacting for 24 h, the NaOH system has higher adsorption than the ethanolamine system. The ASP solutions exhibit a similar trend, which means that the adsorption of polymer is not instantaneous. Conversely, the polymer requires time to accumulate on the sand surfaces. Dynamic Adsorption Experiment. The dynamic polymer adsorption results are shown in Figure 13. The polymer adsorptions decrease with alkali concentration for both alkali

size of the molecules is bigger, which requires a greater loss of conformational entropy of polymer chains on adsorption. Therefore, the adsorption decreases with pH. In addition, the sand surfaces are more negatively charged as pH increases. Meanwhile, high pH results in protons dissociating from the carboxyl groups of polymer. Therefore, the polymer molecules are also negatively charged. Thus, the increased pH causes more repulsion between the polymer and sand surfaces, which results in a reduction in adsorption. On the other hand, the increased alkali concentration also increases the ionic strength. In contrast to the effect of pH, high ionic strength causes compact polymer molecules, which results in smaller of molecule sizes. The smaller-sized molecules require less loss of conformational entropy, so the adsorption will increase. The high ionic strength also causes low viscosity, which decrease the aggregation of sand particles. This increases the amount of surface accessible to the polymer for further adsorption. Therefore, the increase in alkali concentration has influence on two aspects. At low concentration, pH determines the 4589


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Figure 9. Elastic and viscous modulus versus frequency: ASP blend elastic and viscous moduli at different NaOH concentrations (the polymer concentration is 0.1 wt % and the surfactant concentration is 0.15 wt %).

Figure 10. Elastic and viscous modulus versus frequency: ASP blend elastic and viscous moduli at different ethanolamine concentrations (the polymer concentration is 0.1 wt % and the surfactant concentration is 0.15 wt %).

Table 2. Resistance Factors for Alkali−Polymer (AP) Solutions

Table 3. Residual Resistance Factors for Alkali−Polymer (AP) Solutions

Resistance Factor, RF

Residual Resistance Factor, RRF

flow rate (mL/min)

1% NaOH + 0.1% polymer

1% ethanolamine + 0.1% polymer

flow rate (mL/min)

1% NaOH + 0.1% polymer

1% ethanolamine + 0.1% polymer

0.5 1 2 3 4

1.00 2.33 4.25 5.00 5.66

1.67 5.00 8.74 10.59 11.66

0.5 1 2 3 4

1.67 2.67 2.75 2.80 2.83

3.66 4.00 4.00 3.40 3.16

ethanolamine system has lower ionic strength, which results in a lower adsorption of polymer in both AP and ASP solutions. When static and dynamic adsorption are compared, we found that the static measurement has much higher adsorption at the same alkali concentration. The high adsorption for static test is due to the larger surface area that is exhibited by disaggregated sands.

systems. One reason for the decrease may be explained by the decreased viscosity of polymer solutions. As discussed above, the shear viscosity of polymer solutions with alkali concentration, resulting in lower sweep efficiency in the pore media. Therefore, polymer solutions with high alkali concentrations reach less area in the core, which causes lower adsorption. Comparing NaOH- and ethanolamine-based solutions, the 4590


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Figure 11. Static adsorption of polymer with different alkali concentrations.

Figure 12. Effect of time on polymer adsorption.

Figure 13. Dynamic adsorption of polymer with different alkali concentrations. 4591


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Figure 14. Interfacial tension (IFT) of alkali-polymer (AP) and alkali−surfactant−polymer (ASP) solutions with different alkali concentrations.

Figure 15. Cumulative recovery and pressure drop versus PV injected for AP flooding (the polymer concentration is 0.1 wt %).

Table 4. Summary of Sand Pack Flooding Tests experiment type 1% NaOH + 0.1% polymer 1% ethanolamine + 0.1% polymer 1% NaOH + 0.1% polymer + 0.15% surfactant 1% ethanolamine + 0.1% polymer + 0.15% surfactant

porosity (%)

permeability (mD)

initial oil saturation (%)

water flooding recovery (%OOIP)

tertiary recovery (%OOIP)

total recovery (%OOIP)

38.4 38.4

326 353

84.7 84.7

42.22 42.88

19.87 34.54

62.09 77.42

38.7

361

83.4

41.43

26.39

67.82

38.1

382

86

43.18

39.52

82.7

Interfacial Tension (IFT) Test. The IFT test results shown in Figure 14 indicate that the IFT value decreases in all systems as the alkali concentration increases. For AP solution, the IFT value decreases from 2.197 mN/m to 0.42 mN/m when the NaOH concentration increases from 0.25 wt % to 1 wt %. Similarly, the IFT value decreases from 5.825 mN/m to 0.807 mN/m when the ethanolamine concentration increases from

0.25 wt % to 1 wt %. The decrease in IFT improves the oil recovery in NaOH- and ethanolamine-based AP flooding, respectively. Comparing NaOH with ethanolamine, IFT does not exhibit much difference at low concentration (0.25 wt %) and high concentration (1 wt %). Therefore, the determining factor for oil recovery is not IFT but the viscosity between NaOH and ethanolamine. The ASP solution has the similar 4592


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Figure 16. Comparison of emulsification between NaOH and ethanolamine (alkali concentrations, from left to right, are 0, 0.25, 0.5, 0.75, and 1 wt % for each photograph).

Figure 17. Cumulative recovery and pressure drop versus PV injected for ASP flooding (the polymer concentration is 0.1 wt % and the surfactant concentration is 0.15 wt %).

tendency with AP solution. In addition, for ASP solution, the IFT value of ethanolamine solution is much closer to NaOH solution. It means ethanolamine has better synergy with the surfactant. Oil Recovery Performance. The oil recovery and pressure drop profile during the AP flooding are shown in Figure 15, and a summary of the flooding test data is shown in Table 4. For both cases, the oil recovery due to primary water flooding before ethanolamine−polymer flooding and NaOH− polymer flooding is in range of 42%−43%. The pressure during the water flooding also exhibits the same trend. As chemical solution is injected into the core, the pressure increases, because of the interaction between solution and porous media. The pressure reaches 641.2 kPa in ethanolamine−polymer flooding, which is higher than that of NaOH−polymer (324.1 kPa) flooding. This can be attributed to the higher shear viscosity of ethanolamine−polymer solution, which was discussed in the previous section. The breakthrough of ethanolamine−polymer flooding occurs at 2.22 PV, while that of NaOH−polymer solution occurs at ∼2.11 PV. This observation indicates that ethanolamine−HPAM solution moves slower than NaOH−HPAM solution, and 0.11 PV more solution contributes to improved sweep efficiency. For ethanolamine−polymer flooding, the oil recovery increases

sharply after breakthrough, indicating that the ethanolamine− polymer slug pushes the oil bank effectively. As a result of AP flooding, 16.38% additional oil is produced in ethanolamine− polymer slug, compared to 7.43% for NaOH−polymer slug. After AP flooding, post waterflooding is conducted for 1.5 PV at the same flow rate. The total oil recovery of the ethanolamine−polymer case after post-waterflooding is 77.42% and that of the NaOH−polymer case is 62.09%. The emulsification tests results shown in Figure 16 indicate that ethanolamine has better emulsification performance at each concentration, because the oil emulsion was more stable, even after 60 min for organic alkali, compared to its inorganic counterpart. Therefore, the ethanolamine can emulsify the oil into smaller droplets, which is beneficial for entrainment and entrapment. As discussed in the Adsorption Experiments section, ethanolamine has lower adsorption on sand, which means the effect of alkali can be maintained for a long distance in a reservoir. Compared to that observed in Figure 14, the IFTs are lower in NaOH systems than in ethanolamine at the same concentrations. However, NaOH has high adsorption on sand, which means the NaOH has a lower effective concentration than ethanolamine. Therefore, the IFT of ethanolamine systems will be similar to or even lower than that observed 4593


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Energy & Fuels Notes

with NaOH systems. Namely, ethanolamine is good at maintaining a low IFT value, which is an important factor for high oil recovery. High RF and RRF values are the governing factors for improved performance of ethanolamine alkali during AP flood over NaOH. Although the pore blocking by AP solution should be optimized, since high RF and RRF values result in high injection pressure, as discussed in the Injectivity Experiments section, there is no problem with regard to practical application in oil fields. Comparison of ethanolamine and NaOH in ASP flooding was conducted, and the oil recovery and pressure are shown in Figure 17. The pressure during ethanolamine−surfactant− polymer flooding is significantly higher than that during NaOH−surfactant−polymer flooding after primary water flooding. The tertiary recovery of ethanolamine-based ASP flooding case is 39.52%, which is 13.13% higher than observed for NaOH-based ASP flooding. It is due to the less-viscous loss and better sweep efficiency in the ethanolamine system, compared to the NaOH system. The total recovery increases with the addition of surfactant. For the NaOH system, the total recovery increased from 62.09% to 67.82%; for the ethanolamine system, it increased from 77.42% to 82.7%. It also demonstrates that the oil recovery is not only related to the sweep efficiency but also the displacement efficiency.

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors wish to acknowledge the financial support from China Scholarship Council, NSERC Discovery Grant and University of Alberta for this research. The equipment used during the experiments were partially supported through Carbon Management Canada. We also extend our thanks to SNF SAS for polymer samples.

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CONCLUSION (1) The polymer solution with ethanolamine has better shear viscosity and elastic properties at room temperature. The addition of a surfactant has no significant effect on the shear viscosity of the polymer. (2) Ethanolamine has better emulsification performance at each concentrations, because the oil emulsion was more stable, even after 60 min. (3) Injectivity tests were also conducted. The results indicated that resistance factor (RF) and residual resistance factor (RRF) values for the ethanolamine−polymer solution were always higher at each flow rate tested, in comparison to that observed for the NaOH-based AP solution. (4) For the alkali−surfactant−polymer (ASP) solution, the interfacial tension (IFT) of the ethanolamine solution is much closer to that of the NaOH solution, and ethanolamine has better synergy with the surfactant. (5) Polymer adsorption using both static and dynamic measurements was conducted. The polymer solution in the ethanolamine system has lower adsorption for both measurements, because ethanolamine has lower ionic strength. (6) Core flooding experiments were tested in homogeneous sand packing and the performance of the ethanolamine− polymer solution and the NaOH−polymer solution was compared. The pressure comparison during flooding shows that it has higher injection pressure under ethanolamine conditions, which results in good sweep efficiency. The ethanolamine−polymer flooding showed a significant increase in oil recovery (15.33%) over NaOH−polymer flooding. After the addition of surfactant, the total recovery improves by 14.8% for ethanolamine−polymer−surfactant flooding over its inorganic counterpart.

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REFERENCES

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*Tel.: 18810415302. E-mail: [email protected]. 4594


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