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Energy Sources, Part A: Recovery, Utilization, and Environmental Effects

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Effective Factors on Viscosity of ASP Solutions:

Experiments and Simulations

N T B Nguyen, H X Nguyen, W Bae & C T Q Dang

To cite this article: N T B Nguyen, H X Nguyen, W Bae & C T Q Dang (2015)

Effective Factors on Viscosity of ASP Solutions: Experiments and Simulations, Energy Sources, Part A: Recovery, Utilization, and Environmental Effects, 37:24, 2745-2753, DOI:

10.1080/15567036.2012.677938

To link to this article: http://dx.doi.org/10.1080/15567036.2012.677938

Published online: 11 Dec 2015

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Effective Factors on Viscosity of ASP Solutions: Experiments

and Simulations

N T B Nguyen,1 H X Nguyen,1,2W Bae,1 and C T Q Dang3

1

Department of Earth and Environmental Sciences, Sejong University, Seoul, Korea

2

Faculty of Geology and Petroleum Engineering, Ho Chi Minh City University

of Technology, Ho Chi Minh City, Vietnam

3

University of Calgary, Calgary, Alberta, Canada

This article presents the preliminary experiments, which were studied to evaluate the viscosity of alkaline/surfactant/polymer solution before doing phase behavior experiments The results of the experiments provide the effective trend of parameters on viscosity Moreover, the design of the experiment model was conducted by using Minitab software in order to determine the optimum concentration of each chemical in alkaline/surfactant/polymer solution, which has viscosity higher than oil viscosity Importantly, the results of the model showed the interaction among effective factors and, finally, recommended more accurate concentration of each component Consequently, these solutions can push oil bank in the front leading to increase oil recovery

Keywords: alkalis, DOE model, polymer, surfactants, viscosity

INTRODUCTION

In oil production, water is a first and effective fluid for maintaining reservoir pressure and driving oil towards a producer However, the oil production after waterflooding is limited by geology and fluid flow machenism (trapping) When the water saturation increases, oil is trapped as capillary forces cause the water to collect at pore throats Thus, water blocks movement of oil Then, chemical flooding was proposed to enhance oil recovery Surfactant, polymer, and foams can be used to both reduce trapping and improve sweep efficiency Surfactants are useful because they reduce capillary forces and free the trapped oil This method can apply in low permibility, high temperature, and salinity reservoirs However, if only surfactant is used, the surfactant will follow the existing water channels in the formation and the low interfacial tension (IFT) front surfactant slug is not stable and will finger Consequently, it still leaves much oil in the reservoir Therefore, surfactant-polymer flooding was proposed to improve the sweep efficiency and then enhance oil recovery

Polymer flooding is used to achieve the mobility control because polymer can increase significantly the viscosity of injected fluid However, polymer flood cannot be employed in a Address correspondence to Prof W Bae, Sejong University, 98 Gunja-dong, Gwangjin-ku, Seoul 143-747, Korea E-mail: wsbae@sejong.ac.kr

Color versions of one or more of the figures in the article can be found online at www.tandfonline.com/ueso

ISSN: 1556-7036 print/1556-7230 online

DOI: 10.1080/15567036.2012.677938

2745

high temperature and high salinity reservoir In addition, unlike surfactant, polymer will not decrease residual oil saturation with a few exceptions However, it will greatly increase sweep efficiency (Liu,2007)

Alkalis can help recover more oil by raising pH Its recovery mechanisms consist of emulsification with entrainment, entrapment, coalescence; wettability alteration; oil phase swelling; disruption of rigid films; and low interfacial tension The most important factor of this method is generation of in-situ surfactant, which reduce IFT between oil and water phases but its optimum salinity is often different from the reservoir salinity The success of this method depends on both chemical and reservoir properties Thus, the alkaline flooding is complicated and the synthesis surfactant is usually added to adjust the optimum salinity (alkaline Surfactant (AS) flooding)

Alkaline/Surfactant/Polymer (ASP) flooding is a process of a combination of chemical functions ASP flooding has been considered to be a promising method for enhanced oil recovery since the 1980s (Nelson et al.,1984; Clark et al.,1988; Olsen et al., 1990; Delshad

et al., 1998; Seethepalli et al., 2004; Liu, 2007; Hou et al, 2006) It enhances oil recovery through three major mechanisms: (1) adding alkaline chemicals converts acids in the oil to soaps and reduces the adsorption of surfactant, (2) added polymer increases the viscosity of the displacing solutions to improve the sweep efficiency, and (3) the synergetic effect of synthesis and in-situ surfactants reduces oil-water interfacial tension to a very low value to improve the pore level displacement efficiency Thus, ASP flooding has shown much better recovery than other methods (Liu, 2007) However, its mechanisms are complicated and not easily understood

In this study, preliminary experiments were conducted to evaluate the viscosity of ASP solution before phase behavior experiments since the viscosity of the solutions is one of the key factors of ASP flooding Viscosity must be higher than the critical displacement viscosity as studied by Hou

et al (2006) in order for both mechanisms of viscosity increasing and IFT lowering to take effect Thus, it influences oil recovery performance

As mentioned in Nasr-El-Din et al (1991), polymer can interact with other chemicals, such as salts, alkalis, and surfactants, then change the chemical and physical nature of the polymer molecule Thus, the combination of chemicals will change the viscosity of polymer solutions Here, the authors have carried out many experiments to learn how alkalis, surfactants, and polymer affect the viscosity of ASP solutions Especially, there is a combination of two surfactants in ASP solutions

In addition, the design of the experimental model was also introduced in this article The interaction between each chemical in ASP solution was learned, which could not be studied from experiments This result can be used to predict the chemical concentration for a specific oil property

EXPERIMENTAL PREPARATION Twosurfactants were used in this study, including docusate sodium (C20H37NaO7S) and nonionic surfactant—Synperonic® PE/F68 These surfactants were purchased from Sigma-Aldrich Co Alcoflood 254S was used as the polymer (purchased from Ciba Specialty Inc., Canada) It is a partially hydrolyzed polyacrylamide polymer Three alkalis, including sodium carbonate, sodium metaborate tetrahydrate, and sodium metasilicate, were purchased from Sigma-Aldrich Co Diethylene glycol butyl ether (>99%) was used as a co-solvent (Sigma-Aldrich Co.) 3-Methyl-1-butanol (>98%) from Sigma-Aldrich Co was used as co-surfactant

The ASP solutions were prepared with different combinations of alkali, surfactant, and polymer concentrations Then, its viscosity was measured by DV II viscometer of Brook

2746 N T B NGUYEN ET AL.

Field Company The statistic of experimental results was input into Minitab to generate the prediction model

RESULTS OF VISCOSITY MEASUREMENTS AND DISCUSSIONS Viscosity effect of ASP solutions on enhanced oil recovery were studied in the previous literature

of Hou et al (2006) They concluded that the enhancement of oil recovery by ASP flooding depends on both the reduction in IFT and the increase in viscosity of the displacing solution An important note is that, when the viscosity is low, the ultra-low IFT system does not lead to higher oil recovery than other systems with high IFT On the other hand, only when the viscosity reached

a certain value that can ensure good sweep efficiency, the ultra-low IFT can effectively improve the pore-level displacement efficiency in heterogeneous reservoirs

However, it is challenging to obtain both effect of the viscosity and the ultra-low IFT to oil recovery since the viscosity of ASP solution is influenced by many parameters in a complicated manner A parametric study of viscosity for ASP systems was conducted and presented in this study

Effect of Polymer Concentration on Viscosity

The main purpose of adding polymer to solution is to increase the viscosity of injection fluids The higher viscosity leads to an increase in the sweep efficiency and prevents an unstable displacement

or channeling The effect of polymer concentration on viscosity is shown inTable 1 Obviously, increasing polymer concentration resulted in an increase in viscosity

Effect of Alkaline Concentration/Types on Viscosity

To understand the effect of alkaline concentration on the viscosity of ASP solution, 19 different ASP solutions were prepared and the viscosities were measured In these solutions, concentrations

of the surfactant, polymer, co-solvent, and co-surfactant were identical, and only the concentration

of alkaline was varied from 0 to 3 wt% Then, the effect of alkaline concentration was also tested at different polymer concentrations and different alkaline types

For solutions with a single-tail surfactant, as shown inFigure 1, the viscosity of ASP solutions decreases with increasing the alkaline concentration for both alkalis (Na2CO3 and NaBO2) However, adding sodium metaborate into solutions reduces the viscosity of solution more quickly than adding sodium carbonate While adding sodium carbonate resulted in a gradual decrease in the

TABLE 1 Effect of Polymer Concentration on Viscositya

No Sample Polymer Concentration, wt% Viscosity, cp (for Na 2 CO 3 )

a ASP solutions consist of polymer scan (alcoflood 254S), 1 wt% docusate sodium, and 0.01 wt% sodium carbonate Chemicals were mixed in 1 wt% brine (NaCl).

Viscosities were measured at a shear rate of 75 rpm.

viscosity (down to 7.4 cp at 1.5 wt% concentration), sodium metaborate caused an abrupt decrease, and no further viscosity reduction was observed up to 1.5 wt% concentration

For solutions with surfactant mixture, the trend of viscosity curves is different from that with single surfactant solution At low polymer concentration (case 0.5 wt%), the viscosity first decreases as alkaline concentration increases, then the viscosity increases with increasing alkaline concentration At higher polymer concentration (case 1.2 wt%), the viscosity is constant at low alkaline concentration and increases with alkaline concentration above 1 wt% (Table 2a) The results show that the effect of polymer in ASP solution is more dominant than alkaline concentration

FIGURE 1 Viscosity of ASP solutions vs alkaline concentration ASP solutions consist of 1.2 wt% polymer (alcoflood 254S), 2.3 wt% docusate sodium, and sodium carbonate (scan) Chemicals were mixed in 1.5 wt% brine (NaCl) Viscosities were measured at shear rate 75 of rpm.

TABLE 2 Effect of Alkaline Concentration/Type on Viscosity

a Effect of Alkaline Concentration on Viscositya No.

Sample

Alkaline Concentration, wt%

Viscosity, cp (0.5 wt%

Polymer)

Viscosity, cp (1.2 wt%

Polymer)

Viscosity, cp (2.5 wt% Polymer)

a ASP solutions consist of 0.5/1.2/2.5 wt% polymer (alcoflood 254S), 0.75 wt% docusate sodium, 0.75 wt% Synperonic and sodium carbonate (scan) Chemicals were mixed in 1 wt% brine (NaCl) Viscosities were measured at shear rate of 75 rpm.

2748 N T B NGUYEN ET AL.

The effect of alkaline type on the viscosity was also tested with sodium carbonate and sodium metasilicate Solutions with sodium metasilicate show higher viscosity than those with sodium carbonate (Table 2b) In order to explain this behavior, the pH values were measured and it was found that the viscosity is well correlated with pH of solutions In other words, increasing pH leads

to an increase in the viscosity of solutions

Effect of Surfactant Ratio

The effect of surfactant ratio in mixtures was studied for 13 samples The fractions of double-tail anionic surfactant (docusate sodium) and nonionic surfactant (synperonic) were varied, and other parameters were kept constant.Table 3ashows the results of viscosity measurement for ASP solutions without co-solvent and co-surfactant Increasing double tail anionic surfactant (samples 1, 2, and 3) increases viscosity of solutions while increasing nonionic surfactant (samples 1, 4, and 5) decreases viscosity of those solutions It can be explained that increasing the anionic surfactant concentration or decreasing nonionic surfactant makes the polymer more soluble due to the interaction between anionic surfactant and amide groups in polymer Thus, viscosity of ASP solution increases

In addition, samples with added co-solvent and co-surfactant were tested and the results are shown inTable 3b The behavior of viscosity is similar to that without co-solvent and co-surfactant However, the range of variation is wider This shows that co-solvent/co-surfactant may be used to adjust the viscosity of ASP solution

TABLE 2 (Continued)

b Effect of Alkaline Type on the Viscosity of ASP Solutionsa Sample

No.

Brine Conc., wt%

Alkaline Type

Alkaline Conc., wt%

Surf.

Ratio

Surf.

Conc.

Pol Conc., wt%

Viscosity,

a Viscosities were measured at a shear rate of 120 rpm.

TABLE 3 Effect of Surfactant Ratio on Viscosity

a Without Co-surfactant and Co-solventa

No Sample

Surfactant 1 Concentration, wt% (Docusate Sodium)

Surfactant 2 Concentration, wt% (Docusate Sodium) Surfactant Ratio

Viscosity, cp (for NaBO 2 )

a

ASP solutions consist of 1 wt% polymer (alcoflood 254S), surfactant scan, and 1 wt% sodium metaborate hydrate Chemicals were mixed in 1 wt% brine (NaCl) Viscosities were measured at shear rate of 75 rpm.

INTERACTION ANALYSIS OF EFFECTIVE FACTORS The design of experiments model was conducted by using Minitab software to evaluate the interac-tion among chemicals on viscosity of ASP soluinterac-tions The input data include polymer, surfactant 1, surfactant 2, alkaline, salt concentrations, and viscosity responses Those were taken from 32 samples

of the experiments The statistic result of the estimated regression coefficients for viscosity was computed inTable 4 This proved that the model has a high confidence level (R2= 99.8%) Most of the variables are significant when P value < 0.05; therefore, these individual parameters have strongly affected viscosity, neglecting salt and surfactant 2 concentrations

In addition,Figure 2 shows the contour plot of viscosity versus effective factors It presents the interaction of two factors on viscosity of ASP solutions Besides salt and surfactant 2 (synperonic) concentrations, alkaline concentration also affects on viscosity insignificantly (Figures 2a and 2b), only polymer and surfactant 1 (docusate sodium) highly influence on viscosity (Figures 2a–2f)

Based on the high R-sq (prediction) of 98.32% in Table 4, the model can predict optimum concentrations for the desired viscosity at 7cp (Figure 3) The best formulation of ASP solution is

TABLE 3 (Continued)

b With Co-surfactant and Co-solventa

No Sample

Surfactant 1 Concentration, wt% (Docusate Sodium)

Surfactant 2 Concentration, wt% (Docusate Sodium) Surfactant Ratio

Viscosity, cp (for NaBO 2 )

a ASP solutions consist of 1 wt% polymer (alcoflood 254S), surfactant scan, 0.3 wt% diethylene glycol butyl ether, 0.15 wt% 3-methyl-1-butanol, and 1 wt% sodium metaborate hydrate Chemicals were mixed in 1 wt% brine water (NaCl) Viscosities were measured at shear rate 75 of rpm.

TABLE 4 Estimated Regression Coefficients for Viscosity

S = 0.502065; PRESS = 38.4892;

R-Sq = 99.80%; R-Sq(pred) = 98.32%; R-Sq(adj) = 99.67%.

2750 N T B NGUYEN ET AL.

0.6 wt% of polymer concentration, 3 wt% of alkaline concentration, and 0.75 wt% of surfactant 1

at 3 wt% of salt concentration (red value inFigure 3)

CONCLUSIONS

A series of experiments and DOE simulation was used to study the important factors that affect the viscosity of ASP solutions Several conclusions drawn from this study are as follows:

● Increasing alkaline concentration leads to a decrease in viscosity for both alkalis of sodium carbonate and sodium metaborate Moreover, sodium metaborate reduces viscosity more quickly than sodium carbonate

FIGURE 2 Contour plot of viscosity vs effective factors.

● For the surfactant mixture of docusate sodium and synperonic, with increasing alkaline concentration, viscosity first decreases to a critical value and then increases back

● Increasing polymer (alcoflood 254S) concentration increases viscosity

● Increasing anionic surfactant concentration increases viscosity, while increasing nonionic surfactant concentration decreases viscosity

● Co-solvent/co-surfactant may be used to adjust the viscosity of solution

● Considering the interaction among each chemical in ASP solution, polymer and surfactant 1 have strongly affected viscosity, while other factors are less

ACKNOWLEDGMENT The authors wish to thank K K Schlumberger for the encouragement in writing this paper

FUNDING This work was supported by the Energy Resources R&D program of the Korea Institute of Energy Technology Evaluation and Planning (KETEP) grant funded by the Korea Government Ministry of Knowledge Economy (No 2011201030006A)

REFERENCES Clark, S., Pitts, M., and Smith, S 1988 Design and application of an alkaline-surfactant-polymer system to the West Kiehl field SPE Paper 17538 SPE Advanced Technology Series, Vol.1, April.

FIGURE 3 The optimization of components based on the objective function response surface.

2752 N T B NGUYEN ET AL.

Delshad, M., Han, W., Pope, G., Sepehrnoori, K., Wu, W., and Yang, R 1998 Alkaline/surfactant/polymer flood predictions for the Karamay oil field SPE Paper 39610 SPE/DOE Improved Oil Recovery Symposium, Tulsa, OK, April 19–22 Hou, J., Dong, M., Yang, J., Liu, Z., and Yue, X 2006 Effect of viscosity of alkaline/surfactant/polymer (ASP) solution on enhanced oil recovery in heterogeneous reservoirs J Canadian Petroleum Technology 45.

Liu, S 2007 Alkaline surfactant polymer enhanced oil recovery process Ph.D Thesis, Rice University, Houston, Texas Nasr-El-Din, H A., Hawkins, B F., and Green, K A 1991 Viscosity behavior of alkaline, surfactant, polyacrylamide solutions used for enhanced oil recovery SPE Paper 21028 SPE International Symposium on Oilfield Chemicals, Anaheim, CA, February 20 –22.

Nelson, R., Lawson, J., Thigpen, D., and Stegemeier, G 1984 Co-surfactant enhanced alkaline flooding SPE Paper 12672 SPE Enhanced Oil Recovery Symposium, Tulsa, OK, April 15 –18.

Olsen, D., Hicks, M., Hurd, B., Sinnokrot, A., and Sweigart, C 1990 Design of a novel flooding system for an oil-wet central Texas carbonate reservoir SPE Paper 20224 SPE Seventh Symposium on Enhanced Oil Recovery, Tulsa, OK, April 22 –25 Seethepalli, A., Adibhatla, B., and Mohanty, K 2004 Wettability alternation during surfactant flooding of carbonate reservoir SPE Paper 89423 SPE/DOE 14th Symposium on Improved Oil Recovery, Tulsa, OK, April 17 –21.