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A Systematic Study on the Impact of Surfactant Chain Length on Dynamic Interfacial Properties in Porous Media: Implications for Enhanced Oil Recovery Vahideh Mirchi, Soheil Saraji, Morteza Akbarabadi, Lamia Goual, and Mohammad Piri Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.7b02623 • Publication Date (Web): 16 Oct 2017 Downloaded from http://pubs.acs.org on October 17, 2017

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Industrial & Engineering Chemistry Research

A Systematic Study on the Impact of Surfactant Chain Length on Dynamic Interfacial Properties in Porous Media: Implications for Enhanced Oil Recovery Vahideh Mirchi,∗ Soheil Saraji, Morteza Akbarabadi, Lamia Goual, and Mohammad Piri Department of Petroleum Engineering, University of Wyoming, Laramie, Wyoming, USA, 82071 E-mail: [email protected] Abstract We proposed a new systematic procedure to investigate the effect of hydrophobic and hydrophilic chain lengths of Polyoxyethylenated (POE) nonionic surfactants on dynamic interfacial properties in porous media. We studied the impact of nonionic surfactant structure on oil recovery through comprehensive experimental measurements of phase behavior, cloud point, dynamic interfacial tension, dynamic contact angle, and spontaneous and forced imbibitions at ambient and reservoir conditions. We identified a surfactant structure that increased the oil production by 22% and 6% compared to tap water and a nonionic surfactant commercially deployed in a major unconventional oil reservoir, respectively. In this work, we observed that typical factors such as minimum interfacial tension that are determining parameters in bulk phases for surfactant selection are not the only factors at the pore scale. The results of this study revealed

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that when a surfactant solution imbibes into the pore space as an invading phase, the surfactant ability to lower the IFT and reach faster equilibrium plays an important role in the local trapping of oil phase on a pore by pore basis. We proposed a mechanism relating this surfactant behavior to oil-brine displacement and confirmed our results by visual observation of in-situ fluids occupancies after surfactant flood in micromodels and naturally-occurring porous media using light and X-ray microscopy, respectively.

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1

Introduction

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The United States’ projected annual energy growth from 2010 through 2035 is 0.3%, from

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which 37% will be produced from petroleum resources. 1 Chemical flooding is one of the

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widely used Enhanced Oil Recovery (EOR) methods to improve oil production from con-

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ventional and unconventional reservoirs 2,3 Surfactants have been used as EOR agents to

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decrease interfacial tension (IFT) between oil and brine, leading to an increase in oil produc-

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tion 4,5 An extensive body of work in the literature have been devoted to screen surfactant

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formulations as a potential method for enhance oil recovery. 2,6 These studies are mainly fo-

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cused on equilibrium interfacial properties of oil/brine/surfactant systems at the bulk scale

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such as Hydrophilic Lipophilic balance (HLB), 7 Winsor type and R-ratio, 8 and Hydrophilic

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Lipophilic Difference (HLD). 9 Therefore, the determining factors are based on formation

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of oil/brine middle-phase microemulsion or attainment of minimum equilibrium interfacial

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tension as an offset to reduce capillary pressure in oil reservoirs. 10 Despite the numerous

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investigations at equilibrium conditions and in bulk phases, screening surfactant formula-

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tions on the basis of dynamic and in-situ parameters considering the physics controlling the

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surfactant behavior in porous media is absent. This can include parameters such as the

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speed by which surfactants alter the local capillary pressure and pore-scale fluids transport

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in porous media.

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Surfactants behave differently as their structures are altered. The differences can be

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measured through surface/interfacial tension, turbidity, solubilization, and emulsification of 2 ACS Paragon Plus Environment

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surfactant solutions. 11 The decline in IFT using surfactants enhances the dispersion of one

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phase in another phase, resulting in emulsion formation. 12 Emulsions and microemulsions

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may cause formation damage particularly in tight reservoirs with low porosity and perme-

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ability. They also cause high pressure drops in flow lines and the production of off-spec crude

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oil. 12 It is therefore common to use demulsifying surfactants in tight petroleum reservoirs to

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avoid operational difficulties during production. Studies have demonstrated that the equal

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partitioning of surfactants between oil and brine phases gives the highest demulsifying effi-

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ciency. 13–15 However, Xu and co-workers suggested that weak emulsifiers that are also IFT

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reducers are more beneficial to the oil recovery than demulsifiers. 16 Therefore, for a surfac-

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tant/rock/oil/brine system, it is desirable to use surfactants with low IFT and no-or-weak

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emulsifying ability to generate less emulsion and higher recovery. 16

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Surfactant solubility is an indication to ascertain that the chemical is able to remain

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active in brine and travel into the matrix at reservoir temperature. Solubility of surfactants

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in aqueous solutions can directly impact interfacial properties such as IFT and therefore oil

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recovery. The solubility of an aqueous nonionic surfactant solution is strongly dependent

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on temperature and is manifested by cloud point temperature (CPT). This temperature is

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highly dependent on the arrangement of hydrophobic and hydrophilic parts of surfactants.

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Inoue et al. 17 investigated the cloud point of several solutions of polyoxyethylene (POE)-type

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nonionic surfactants in 1-butyl-3-methylimidazolium tetrafluoroborate. They found that the

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cloud point temperature increases with POE chain length and decreases with increase in the

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hydrocarbon chain length.

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There have been many independent investigations on the impact of surfactants on the

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surface/interfacial tension, contact angle, solubility, and emulsification at ambient conditions

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for applications in oil recovery from conventional and tight reservoirs. 18–23 However, these

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fundamental parameters were rarely examined at reservoir conditions. While a better under-

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standing of fluid/fluid and rock/fluid interactions at reservoir conditions is essential for the

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optimization of surfactant formulations. The physical characteristics of surfactant molecules



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as well as rock properties vary as temperature and pressure conditions of the system are

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altered. 24 More importantly, the above-mentioned parameters were mainly studied at equi-

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librium conditions, even though the adsorption of surfactants at liquid/liquid or liquid/solid

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interfaces is a dynamic process. For instance, Nguyen et al. 25 measured the equilibrium

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interfacial tension (IFT) of crude oil and various surfactant solutions at 80 ◦ C and found no

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correlation between IFT and oil recovery from reservoir shale samples.

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To confirm the relevance of interfacial parameters to surfactant behavior inside porous

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media, one must study their impacts on rock samples. This can be achieved through spon-

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taneous imbibition and core flooding experiments as well as contact angle measurements.

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Several studies on the spontaneous imbibition of surfactant solutions in tight formations

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have been presented in the literature. 18,26–31 However, there is a lack of systematic assess-

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ment on the impact of surfactant structures on enhancing oil recovery. The majority of

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these studies investigated oil/gas recovery from rock samples using different known and/or

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unknown surfactant structures. For instance, Alvarez and coworkers studied the effect of

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different surfactants on wettability alteration of unconventional rocks using spontaneous im-

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bibition experiments. 32–35 Nevertheless, their investigation did not include any assessment

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on surfactant structures and their impact on enhancing oil recovery.

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The objective of this study is to establish a systematic methodology to investigate the

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impact of POE surfactant structures (a group of environmentally-friendly nonionic surfac-

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tants) on oil recovery in naturally-occurring porous media. All surfactants were first assessed

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through emulsification and solubilization tests at ambient and high temperatures. There-

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after, dynamic interfacial tensions and contact angles of crude oil and different surfactant

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solutions were measured at both ambient and reservoir conditions. These were then used

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to develop correlations between the interfacial parameters and the structure of surfactants.

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Subsequently, spontaneous imbibition tests were performed in relatively low permeability

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limestone and sandstone samples to study the effect of selected surfactant structures on

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oil recovery from porous rocks. These rocks were selected as analogs of dolomitic siltstone


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reservoir rock samples to investigate the influence of mineralogy and pore structure on oil

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recovery. The study was then extended to rock samples obtained from a major unconven-

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tional oil reservoir. Spontaneous imbibition experiments were performed, using one of the

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best performing surfactants, and the results were then compared to those of a base nonionic

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surfactant formerly deployed in this reservoir. As a result, a relationship between the struc-

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ture of the surfactants and oil recovery from limestone, sandstone, and reservoir samples

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was identified. The performance of short-listed surfactants was verified through forced core

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flooding experiments at reservoir conditions. The results were then compared to those of the

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base surfactant. Lastly, we present a displacement mechanism based on dynamic interfacial

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tension trends using visual observation of in-situ fluid distribution after surfactant flooding

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in micro-models and porous rocks.

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2

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In this section, we present detailed information regarding the rock samples, fluids, chemicals,

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and experimental setups and procedures used in this study.

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2.1

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Preserved reservoir rock samples were employed for contact angle measurements and spon-

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taneous imbibition tests. We received the rock samples as preserved full cores (4 inches in

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diameter) and utilized them as received without further cleaning or conditioning. A micro-

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graph of the reservoir samples obtained using high-resolution scanning electron microscopy

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(SEM) in back-scattered electron (BSE) mode is shown in Figure 1a. An elemental map

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of the samples generated using energy dispersive spectroscopy (EDS) is presented in Figure

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1b. Using three dimensional SEM images, the porosity was measured as about 1.5% and

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the organic content was characterized to be less than 1 vol%. 36 The elemental map detected

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the dominant minerals of the reservoir sample as dolomite, calcite, quartz, and illite clays

Materials and methods

Rock samples



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in order of abundance. This order of mineralogy abundance was also confirmed using X-ray

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diffraction (XRD) results. We identified the preserved rock sample as dolomitic siltstone.

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Since the targeted reservoir samples were rich in calcite and quartz minerals, we decided to

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use outcrop samples, i.e., Edwards limestone and Berea sandstone, as test porous mediums

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for surfactant screening steps using spontaneous imbibition. It is also reported in the lit-

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erature that even though conventional and unconventional rocks have different properties,

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core flooding experiments performed on conventional rocks can provide some relevant in-

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sights into the physics controlling the displacement mechanism in unconventional rocks. 37,38

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A helium porosimeter-permeameter was used to experimentally measure the porosity and

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permeability of the rocks as shown in Table 1. Figure 2 shows two-dimensional images of

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Edwards limestone and Berea sandstone rock samples obtained using high-resolution X-ray

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microtomography and scanning electron microscopy. The pore size distributions of both

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rocks were characterized by image analysis utilizing AvizoFireTM 8 software (see Figure 2c).

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Based on the pore size distribution analysis shown in Figure 2, Edwards limestone has a

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wider pore size distribution (∼ 1-400 µm) compared to that of Berea sandstone (∼ 1-300

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µm). It shows a bimodal distribution with peaks at 5 and 250 µm pore sizes. Note that since

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the resolution of our imaging instrument was close to the size of the first peak, it could not be

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detected more clearly. However, SEM images confirmed the existence of micro pores in this

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rock (see Figure 2d). Table 1 lists dimensions and basic petrophysical properties of the rock

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samples employed in the spontaneous imbibition experiments. Table 2 lists the dimensions

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and petrophysical properties of Edwards limestone used in forced core flooding experiments.

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We further characterized the pore-to-throat aspect ratio of Edwards limestone and Berea

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sandstone as 4.76 and 3.89, respectively. This was done by measuring the inscribed radii of

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pores and throats using distance transformation method.


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2.2

Fluids

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Crude oil from an unconventional reservoir was utilized in this study. The properties of the

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oil are shown in Table 3. The presented data are obtained from Mirchi et al. 39 The oil was

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first centrifuged at 6000 rpm for one hour and then filtered with 0.5 µm metal filters before

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use. Municipal water was used as the fracturing fluid and reservoir brine was synthesized

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to establish initial brine saturation in the core flooding experiments. The concentrations

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of the dominant cations and anions in municipal water and reservoir brine are presented in

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Table 4. Note that different samples of municipal water were used and the measured ion

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concentrations were comparable. The pH of tap water and reservoir brine were neutral and

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their total dissolved solids (TDS) were about 120 and 320,000 ppm, respectively.

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2.3

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POE-type nonionic surfactants from Stepan and Sigma Aldrich companies were utilized in

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this study without further purification. The chemical formula and structure of 14 poly(ethylene

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oxide) R(OC2 H4 )x OH surfactants with homologous chain distribution are presented in Table

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5 and Figure 3. The hydrophobic part of the molecules consists of alkyl chains, while the

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hydrophilic part is made of ethylene oxide chains. The critical micelle concentration (CMC)

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of all the surfactants was measured at ambient conditions and the results can be found in

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Table 5. In addition to these surfactants, a commercial nonionic surfactant was selected as

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a base surfactant for comparison. This surfactant has been deployed in the unconventional

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oil reservoir under study.

Surfactants



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3

Experimental setup and procedure

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3.1

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Two sets of experiments at both ambient and high temperature were carried out using glass

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tubes (10 cc), which were sealed at the bottom using a flame torch. The test tubes with a

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brine/oil ratio of unity and a fixed salinity of 120 ppm (tap water) were capped and then

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shaken for 24 hours with an incubator shaker at a speed of 200 strokes/minute. Tests at high

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temperature were performed, while the temperature inside the shaker was kept constant at

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80 ◦ C. Thereafter, the tubes were monitored at room temperature for several days until no

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further change was observed.

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3.2

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Dynamic interfacial tensions and contact angles were measured using rising/captive bubble

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tensiometry enhanced by image acquisition with a high-resolution Charged Coupled Device

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(CCD) digital camera and apochromatically-corrected lens. The apparatus includes a Hastel-

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loy measurement cell, a Hastelloy dual-cylinder pulse-free Quizix pump (to provide constant

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flow rate and pressure), a temperature control module, a data acquisition computer, an oven,

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and an in-line density meter (Anton Paar DMA HPM) to measure the density of fluids at

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actual experimental conditions. The system can tolerate reservoir conditions with pressures

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and temperatures up to 10,000 psi and 150 ◦ C, respectively. This experimental setup and

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associated measurement procedures were validated in our previous study for both IFT and

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contact angle (CA) measurements. 40

Phase behavior

IFT and contact angle

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For IFT measurements, after establishing ambient (i.e., 14.7 psi and 20 ◦ C) or reservoir

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conditions (i.e., 6840 psi and 120 ◦ C) in a cell saturated with brine, a bubble of crude oil

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was created inside the measurement cell through a needle (0.3-1.6 mm outside diameter).

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Images of oil bubbles were captured with time at 5 s intervals to measure dynamic interfacial


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tension. IFT values were obtained using the Axisymmetric Drop Shape Analysis (ADSA)

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software and by fitting the drop profile to the Young-Laplace equation.

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Prior to dynamic contact angle measurements, reservoir rock samples were cut using a

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precision saw and polished to create a smooth surface and to remove irregular and uneven

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areas. The surface roughness of our substrates is expected to be lower than 1 µm. 39 The rock

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substrate was then placed on a sample holder inside the measurement cell and the cell was

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filled with brine solution. In these measurements, images were captured while oil bubbles

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were slowly (i.e., 0.005 cc/min) swollen or shrunk beneath the rock surface using a Quizix

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pump (See Figure 4a). For static contact angle measurement, limestone and sandstone rock

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samples were cut and then vacuum saturated with crude oil. The saturated samples were

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then immersed in brine solution. The static contact angles were captured with a CCD camera

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equipped with a suitable magnifying lens, after crude oil was produced from the sample by

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brine imbibition (See Figure) 4b). The captured images of dynamic and static bubbles were

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then analyzed by ImageJ software and the CA was determined by measuring the angles

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made by the tangent line on the bubbles through the brine phase. More information on the

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experimental procedure is provided elsewhere. 39

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3.3

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In this study, the surfactant solutions were injected into the measurement cell described in

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Section 3.2 utilizing a Quizix pump. After reaching the reservoir pressure (6840 psi), the

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solution was heated using a heating jacket (Glas-col, LLC) firmly wrapped around the mea-

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surement cell. The temperature was gradually raised (' 0.4 ◦ C/min) from ambient to the

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maximum of 120 ◦ C (reservoir temperature). A mounted resistance temperature detector

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(RTD) inside the cell (with accuracy of ± 0.1 ◦ C) was utilized to check the internal temper-

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ature. Surfactant solutions were then monitored visually by a digital camera attached to a

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microscope. The temperature above which surfactant solutions became turbid was identified

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as the cloud point temperature. 41–43 For simplicity, some of the low CPTs were measured

Cloud point temperature



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at atmospheric pressure in a water bath. Comparing ambient and reservoir pressure tests

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conducted for a few surfactants, we found pressure to have negligible effect on surfactant

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turbidity. The measured could point temperatures for the selected surfactants are presented

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in Figure 5.

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3.4

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The experiments were performed on cylindrical Edwards limestone, Berea sandstone, and

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reservoir core samples at ambient conditions. The cores were initially vacuumed using a

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robust vacuum pump (TRIVAC Vane, ∼ 10−7 psi) for one and three days for outcrop and

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reservoir samples, respectively. Thereafter, the crude oil was gradually introduced to the

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cores inside the vacuum cell until the entire rock was immersed in the fluid. The above-

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mentioned technique provided 97-99% oil saturation for limestone and sandstone and 70-80%

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for reservoir samples. The saturated cores were then placed in glass imbibition cells with

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a volume accuracy of 0.1 cc and filled with brine from the top. We used a thin V-shaped

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glass spacer beneath the rock to ensure that all faces of the cores were exposed to the brine

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solution. The volume of the produced oil was recorded versus time until no more production

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was observed. Oil production by spontaneous imbibition of brine solution was reported as

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percentage of the original oil in place.

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3.5

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The schematic diagram of the core flooding apparatus is shown in Figure 6. It consists of

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three Quizix pumps, two pumps for oil and water injection and one pump for back pressure

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regulation, two pressure transducers, a dome-loaded back pressure regulator, a manual over-

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burden pressure pump, a cooling bath, and a burette for fluid collection. The core assembly

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was mounted in an oven with temperature control to reach experimental conditions.

Spontaneous imbibition

Waterflooding

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For the flow experiments in this section, we used Edwards limestone samples. The tests

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were performed on cores with an initial water saturation (Swi ) of about 23%. Core samples 10 ACS Paragon Plus Environment

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(3.7 cm in diameter and 15 cm long) were cut from blocks of Edwards limestone and were

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flushed with CO2 and vacuumed to remove any trapped gases inside the medium. Several

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pore volumes of synthetic reservoir brine were then injected with gradually increasing flow

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rate at both ambient and reservoir conditions. Brine absolute permeability was quantified by

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measuring the differential pressure across the core at this stage. Average porosity was also

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determined using total volume and the weight difference of the core before and after satura-

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tion with brine. Once the cores were saturated with reservoir brine at reservoir conditions,

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each core sample was subjected to primary drainage, primary imbibition, and secondary

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drainage tests. To mitigate the effect of potential gravity segregation, brine was injected

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from bottom of the core holder.

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Initial water saturation was established by oil injection (primary drainage) at reservoir

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conditions. At this point, injection of different surfactant solutions was performed at a

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constant flow rate of 0.1 cc/min (primary imbibition). This flow rate provided a capillary-

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dominated displacement regime with an average capillary number of 1.355×10−6 for all the

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IFT values used in this study. The capillary numbers were calculated using Equation 1.

Nc =

µb u b σob φ

(1)

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where µb , ub , φ and σ ob are the viscosity, Darcy velocity of brine, porosity of sample and

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the interfacial tension between oil and brine, respectively. Residual oil saturation (Sor ) was

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determined at the end of this stage (Q = 0.1 cc/min) via volume and mass balance. In order

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to simulate the flowback process after hydraulic fracturing, the last stage of core flooding

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experiments included oil injection (secondary drainage) at reservoir conditions. This was

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done to assess the influence of different surfactant structures on remaining water saturation

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(Swr ). Throughout the experiments, the outlet and confining pressures of the cores were

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maintained at 6840 psi and 8100 psi, respectively. 11 ACS Paragon Plus Environment


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4

Results and discussion

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In this section, we discuss the results and explore the impact of hydrophilic and hydrophobic

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surfactant chain length on interfacial properties and oil recovery using nonionic surfactant

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solutions and different rock samples.

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4.1

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Visual phase behavior tests were performed as a qualitative tool at ambient and elevated

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temperatures (20 ◦ C and 80 ◦ C) to evaluate the tendency of surfactants for emulsification.

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These tests were performed for all nonionic surfactants considered in this study at a water/oil

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ratio of unity. Using alcohol ethoxylates with varying number of Ethylene Oxide (EO) and

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CH3 (CH2 )n side chains, a relationship between surfactant structure and their emulsification

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behavior was identified. Figure 7 shows the impact of the elongation of the hydrophilic and

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hydrophobic chains of the surfactants on their emulsification tendency.

Emulsification

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As shown in Figure 7, for a fixed alkyl chain of 8-10, 10, and 11-14, increasing the

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number of ethylene oxide increases the amount of microemulsion phase in the middle of

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the test tube. This trend was more evident when the hydrophobic chain was longer. For

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instance, surfactants with a fixed hydrophilic side and longer alkyl chain of 11-14 produced

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more microemulsions compared to that of 8-10. This figure exhibits the classical Winsor

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type III phase behavior where surfactant rich middle phase coexists with both oil and brine

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phases. 4 The base surfactant, however, did not produce any third phase between oil and brine

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phases. The high-resolution transmission electron microscopy (HRTEM) images shown in

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Figure 7 present the microemulsion phase extracted from the rag layer between oil and brine

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phases. The samples were prepared by diluting the microemulsions 20 times in the brine

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phase. It appears that the average size of microemulsions is about 100 nm.

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The formation of microemulsions depends on the surface activity of the surfactants. 44

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As the surfactant molecules diffuse from the bulk phase to the brine/oil inte rface, their 12 ACS Paragon Plus Environment

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hydrophobic tails adsorb on the oleic phase, while their hydrophilic heads partition into

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the aqueous phase. Interface partitioning of surfactants increases as their hydrophilic chain

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becomes larger, yielding a greater chance of forming microemulsions. Generally, for a surfac-

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tant to behave as an emulsifier, a considerable surface activity coupled with low IFT values

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is required. This can be achieved by increasing the length of the POE chain according to

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previous studies. 45 However, a number of studies have shown that even though lowering IFT

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enhances emulsion stability, ultra-low IFT can destabilize the emulsions 15,46,47 .

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4.2

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In order to examine the surface activity of the surfactants, a series of dynamic IFT measure-

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ments with municipal water and crude oil were performed at ambient conditions. Figure 8

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presents dynamic IFT results of a homologous series of nonionic surfactant solutions with

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0.1%wt concentration. This concentration is above the CMC of all the surfactants studied

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in this work. Note that each presented IFT curve is the average of at least 3 measurements

279

with a very small error bar (less than 0.1 mN/m). In these tests, the size of the hydrophobic

280

and hydrophilic parts of the surfactants were altered independently and their impact on

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brine/oil interfacial tension was investigated.

Efficiency in IFT reduction

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As shown in Figure 8a, for a fixed hydrocarbon chain length of 8-10 CH2 , increasing the

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degree of ethoxyaltion (from very small amount of 2.5 to 8.3 moles) reduced the IFT between

284

oil and brine. Similar results were also observed using surfactants with 10 and 11-14 carbons

285

in alkyl chain and increasing ethoxylation degree (Figures 8b and 8c). This is attributed to

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the solubilization capacity of the surfactants in aqueous phase. For a very short polar head,

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dissolution in water is limited as hydration forces are chiefly responsible for solubility. As a

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result, cloudy brine solutions are formed. On the other hand, elongation of ethylene oxide

289

chains from very small to medium range, enhances the aqueous solubility of surfactants,

290

resulting in a greater migration of their molecules to the interface and a reduction in IFT.

291

Note that surfactant precipitation in brine solution was observed at ambient conditions using 13 ACS Paragon Plus Environment


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292

Page 14 of 56

surfactants with EO of 2.5 and 3.

293

Increase in the degree of ethoxylation from 8 to 15 moles induced an increase in interfacial

294

tension with fast equilibrium (less than 5 minutes shown in Figure 8d). There are a number

295

of factors impacting the efficiency of surfactant adsorption at liquid/liquid interfaces. Sur-

296

face excess concentration (i.e., surface concentration, Γm ) is a good indicator of surfactant

297

efficiency. It is reversely proportional to the area per molecule that surfactants occupy at

298

the interface at surface saturation asm . 44 The most significant structural impact on Γm is

299

induced by changes in the hydrophilic group. 48 Changes in the hydrophilic chain influence

300

the area per molecule of polyethylenated nonionic surfactants at the interface. For a fixed

301

hydrophobic chain length, the area per molecule rises as the number of ethylene oxide is

302

increased. Consequently, the oil/brine interface is occupied by fewer surfactant molecules,

303

causing a higher IFT. Moreover, as the size of the molecules becomes larger, the interface will

304

be saturated faster and hence equilibrium will be reached sooner. Berger et al. 15 examined

305

the effect of changing the hydrophilic/hydrophobic balance (HLB) of a series of polypropy-

306

lene glycol ethoxylates on IFT. Their results revealed a reduction in IFT to a certain value

307

as HLB was raised and an increase in IFT by further increase in the ratio of hydrophilic to

308

hydrophobic properties of surfactants.

309

The above-mentioned IFT versus EO behavior is in accord with those in the literature

310

and can be explained by Equation 2 49 and Figure 13 that include three typical regions

311

of dynamic IFT reduction, namely: (I) induction region, (II) rapid fall region, and (III)

312

mesoequilibrium region .

log(γ0 − γt ) − log(γt − γm ) = nlogt − nlogt∗

(2)

313

In Equation 2, γt is the IFT of surfactant solution at time t, γm is the mesoequilibrium

314

interfacial tension (when γt is almost stabilized), γ0 is the IFT in the absence of surfactant,

315

and t∗ is the required time for IFT to reach half of its value between γ0 and γm . In this

316

equation, n is a constant number related to the structure of surfactants, which is correlated to 14 ACS Paragon Plus Environment

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317

the difference between adsorption and desorption of surfactants. Based on the work of Gao

318

and Rosen, 50 increasing the polyoxyethylene chain length of nonionic surfactants reduces

319

n. From Equation 2, at a constant surfactant concentration, the maximum rate of change

320

in surface tension decreases as n declines. Therefore, increasing EO chain or decreasing n

321

induces a smaller difference between equilibrium IFT and IFT at any given time, resulting

322

in instantaneous equilibrium. Hua and Rosen 49 provided values of n for a series of nonionic

323

surfactants with fixed carbon number and ethylene oxide chain from 4 to 11. Analysis of

324

their data showed that the reduction of n with the increase of EO degree is slower when the

325

chain is shorter. This implies that the required time for IFT to reach half of its value (t∗ )

326

slightly decreases by increase in the length of POE from low to medium, but dramatically

327

declines for very long hydrophilic chains. We also calculated t∗ for the surfactants used

328

in this study and reported the results in Table 7. As expected, increase in the degree of

329

ethoxylation reduces the time that is required for IFT to reach half of its value.

330

Figure 8e and 8f present the impact of increasing the hydrophobic chain of surfactants

331

on oil/brine interfacial tension. As exhibited in these figures, addition of methylene groups

332

in the alkyl chain, slightly lowers the IFT. Similar trends were observed in previous studies,

333

where a minor increase in the effectiveness of surfactant adsorption at the interface was

334

observed by an increase in alkyl chain length. 44,51 This behavior was explained by the fact

335

that at a fixed oxyethylene chain length, surface excess concentration is slightly affected by

336

the number of methylene groups in the alkyl chain.

337

4.3

Temperature tolerance

338

4.3.1

Surfactant solubility

339

Experimental investigation on the effect of structural arrangement of POE surfactants in-

340

cluding alkyl chain and ethylene oxide on solubility of surfactants was accomplished by Cloud

341

Point Temperature (CPT) measurements. As mentioned earlier, the solubility trends are at-



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

342

tributed to hydrophilicity/hydrophobicity characteristics of the surfactants. Hydration of

343

POE chains requires hydrogen bonding with several water molecules depending on the moles

344

of POE. For instance, water/EO mole ratio is reported to be 6 for C12 E21 . 52,53

345

Therefore, the hydrophilic chain of surfactants plays an important role in the variation of

346

their cloud point temperature as shown in Figure 5. We found that sequential lengthening

347

of POE chain increased the CPT for all different alkyl chains ((CH2 )8−10 , (CH2 )10 , and

348

(CH2 )12 ). The most hydrophilic surfactant with 18 ethylene oxide exhibited CPT of 109.6 ◦ C.

349

Even though this surfactant did not tolerate the reservoir temperature, it was the most

350

suitable one in terms of aqueous solubility. Figure 5 also shows that for a fixed hydrophilic

351

groups, increase in the alkyl chain length of POE-type nonionic surfactants slightly reduced

352

the CPT. Similar behaviors have been reported in previous investigations on surfactant

353

solubility. Curbelo et al. 43 investigated the impact of surfactant structure on cloud point

354

phenomenon for different POE-type nonionic surfactants. Their research showed that CPT

355

increases with lengthening of POE chain due to their higher solvophilicity. It was also

356

reported that for a constant hydrophobic length, the higher is the percentage of oxyethylene,

357

the greater the CPT becomes. 44 In this work, the base surfactant appeared to have a very

358

low CPT of 46.1 ◦ C±1.7 in comparison with the selected surfactants.

359

Page 16 of 56

The solubility and state of orientation between water/oil molecules and hydrophilic/lipophilic

360

parts of surfactants changes as temperature is altered. Accordingly, the aqueous solubility

361

of nonionic surfactants should be assessed at various temperatures in order to establish a

362

comprehensive evaluation of their performance. It has been reported that the hydration

363

force is inversely dependent on temperature. 53–55 Tadros 56 stated that increasing tempera-

364

ture of the nonionic surfactant solutions causes dehydration of POE chain, which results in

365

less interactions with water molecules. This is manifested in the cloudiness of the solution.

366

Cloud point phenomena can also be described through formation of very large aggregates

367

of surfactant molecules. As temperature is raised, the number of aggregates increases. This

368

means that increase in temperature enhances the affinity of surfactants to self aggregate,


Page 17 of 56

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369

resulting in an increase in turbidity of the surfactant solution. Our results are in accord

370

with previous findings in the literature. 44

371

4.3.2

372

Figure 7 displays the impact of temperature on the phase behavior of crude oil and surfactant

373

solutions with different molecular structures. As shown in this figure, temperature signifi-

374

cantly affects the stability of microemulsions. Increasing temperature to 80 ◦ C destabilized

375

the microemulsion phase produced by various surfactant structures. This is because tem-

376

perature impacts the physical properties of the crude oil, water, and surfactant molecules,

377

leading to a reduction of surfactant solubility and a breaking of the microemulsion phase.

378

Temperature can also increase the kinetic energy of molecules in droplets and induce their

379

coalescence. The effect of temperature on the stability of crude oil/water interfacial films was

380

investigated by Jones et al. 57 The authors stated that an increase in temperature may cause

381

destabilization of crude oil/water interfacial films. Salager 58 also reported a reduction in the

382

hydrophilicity of the POE surfactants resulting in a phase behavior transition from Winsor

383

III (middle-phase microemulsion) to Winsor II, where there is no middle phase between oil

384

and brine phases. As it was shown in Section 4.1, increasing the degree of ethoxylation in

385

POE-type surfactants induced the formation of microemulsions. However, they were desta-

386

bilized at elevated temperature, as shown in Figure 7. Therefore, it is not expected that

387

emulsions would cause operational difficulties due to emulsification when these surfactants

388

are deployed in tight formations at high temperatures.

389

4.3.3

390

Following the systematic analysis performed at ambient conditions, a few surfactants were

391

selected for dynamic interfacial tension measurements at actual reservoir conditions. The

392

selected surfactants were further examined to study the impact of elevated temperature

393

and pressure on their performance. IFT values of crude oil and surfactant solutions were

Microemulsion stability

Interfacial activity



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394

measured at 6840 psi and 120 ◦ C using the state-of-the-art apparatus presented in Section

395

3.2. Figure 9 shows the difference between IFTs at ambient versus reservoir conditions.

396

In Figure 9a-d, the difference between IFT values measured at ambient and reservoir con-

397

ditions reduced as the hydrophilic parts of the surfactants were increased. In other words,

398

surfactants with higher cloud point temperatures showed smaller IFT differences. This be-

399

havior can also be described at the molecular level: rise in temperature leads to an increase

400

in thermal motion of the molecules, 59 and hence the area taken by each molecule at the

401

interface would be larger. The coverage of a larger area by the molecules reduces the sur-

402

factant concentration at the oil/brine interface. Therefore, surface activity of surfactants

403

at higher temperature declines, leading to greater IFT. 44 Referring to Figure 8, at ambient

404

conditions, all the selected surfactants with shorter hydrophilic chains, along with the base

405

surfactant, produced smaller IFTs than the ones with very large hydrophilic head. How-

406

ever, at reservoir conditions, their IFT values increased, while the IFT of surfactant EO-18

407

remained unchanged (Figure 9d). Therefore, surfactants with the highest hydrophilicity

408

had the lowest IFTs at reservoir conditions and are more suitable for enhanced oil recovery

409

applications.

410

4.4

411

In order to investigate the effect of various surfactant structures on the wettability of reservoir

412

rock, static and dynamic contact angle measurements were performed at ambient and reser-

413

voir conditions, respectively. Static contact angles of crude oil on limestone and sandstone

414

samples immersed in different surfactant solutions (0.1 wt.%) were measured at ambient

415

conditions and are presented in Figure 10. Dynamic contact angles of crude oil bubbles were

416

measured on prepared rock surfaces in the presence of surfactant solutions (captive bubble).

417

The measurements were performed while the bubble was growing and shrinking beneath the

418

rock surface using a very small flow rate. The data presented for each surfactant (see Figure

419

11) is the average of 30 measured angles obtained at 5 seconds interval.

Wettability


Page 18 of 56

Page 19 of 56

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420

The original wettability of the reservoir rock was found to be water-wet. This was

421

expected due to very low Asphaltene content of the crude oil (see Table 3) and insignificant

422

organic content of the reservoir rock. 60 We found that elongating the ethylene oxide side of

423

nonionic surfactant structure does not impact the wettability state of Edwards limestone and

424

Berea sandstone used in this study (Figure 10). Similarly, the dolomitic siltstone rock surface

425

showed a water-wet behavior with advancing (oil shrinking) and receding (oil expanding)

426

contact angles of 43.19 and 23.19 degrees, respectively. The dynamic contact angle values

427

in Figure 11 remained nearly unchanged with tap water and different surfactant structures.

428

This suggests no sensitivity of reservoir rock’s wettability to nonionic surfactants containing

429

POE chains. These results were expected on the ground of an earlier study by Mirchi and

430

coworkers 39 who compared the adsorption of anionic and nonionic surfactants on reservoir

431

rock samples. Their results showed that the adsorption of nonionic surfactant is much smaller

432

than that of anionic surfactant due to weak van der Waals interactions with functional groups

433

at the rock surface.

434

4.5

Imbibition behavior

435

4.5.1

Spontaneous imbibition

436

We studied the effect of hydrophilic/hydrophobic chain length of nonionic surfactants on oil

437

recovery through spontaneous imbibition experiments. Spontaneous imbibition experiments

438

are impacted significantly by capillary forces in the porous medium in the absence of any

439

applied external forces. As imbibition takes place in a core sample saturated with crude

440

oil, the wetting phase (i.e., water) saturation increases with a rate that depends on pore

441

size distribution, wettability, IFT of fluids, etc. In each set of experiments with limestone

442

and sandstone rocks, core samples with similar wetting state, permeability, and pore size

443

distribution were used, while IFTs were varied using different surfactant structures. The

444

results of spontaneous imbibition tests in limestone and sandstone rock samples with reservoir



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

445

crude oil and different surfactant solutions (0.1 wt%) are shown in Figure 12.The results in

446

each case are the average of 3-4 measurements with an error bar showing the variations. It

447

is noteworthy that the reproducibility of the generated data was satisfactory with a small

448

standard deviation on each curve.

449

Using surfactants with the shortest hydrophilic chain showed only a slight increase in the

450

final oil production against tap water and no improvement compared to the base surfactant

451

in limestone samples (see Figure 12a). This might be due to its precipitation in brine. Nev-

452

ertheless, surfactants with EO of 6.25 and 8.3 produced a higher amount of oil compared to

453

the surfactant with EO of 3 and the base surfactant. Imbibition results with these two sur-

454

factants were close considering the error bars. Similar results were observed for surfactants

455

with alkyl chain of 11-14 (Figure 12c). Considering negligible impact of POE surfactant

456

structure on contact angle results (Figures 10, 11), the stronger imbibition induced by an

457

increase in the hydrophilic side of surfactants is attributed to their higher surface activity,

458

as explained in previous sections. This was in such a way that oil production was inversely

459

correlated to equilibrium IFT value, meaning that lower equilibrium IFT led to higher oil

460

recovery. It is critical to note that the rates of IFT reduction were nearly similar for surfac-

461

tants with low to medium hydrophilic chain (EO=3-8.2), while the equilibrium IFTs were

462

different. Thus, the improvement in oil production upon increasing EO from low to medium

463

can be explained by equilibrium IFT for surfactants with low to medium hydrophilic chain.

464

Similarly, when ethoxylation was increased from medium to high (8.2-18), increasing

465

the hydrophilic chain to EO of 18 provides a higher oil production in limestone samples

466

compared to those of surfactants with the same hydrocarbon chain length and lower ethylene

467

oxide degree (Figure 12c). In contrast to the prior case, superior production was associated

468

with higher IFT values but faster equilibration (i.e., more efficiency). Table 7 shows the

469

relationship between lengthening of the hydrophilic side of surfactant along with associated

470

recovery values. As shown in the table, increase in the degree of ethoxylation reduced the

471

time that was required for IFT to reach half of its value. This in turn was corresponded to


Page 20 of 56

Page 21 of 56

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472

faster oil production. In other words, the oil production from limestone samples is greater

473

when the IFT reduction regions including induction, rapid fall, and mesoequilibrium are very

474

close to each other. This creates a relatively flat line for dynamic IFT values, as presented

475

in Figures 8 and 13.

476

Spontaneous imbibition tests in sandstone rock samples revealed an analogous behavior

477

when increasing the ethylene oxide chain side of the surfactants. However, the trend is

478

more significant on the rate of oil production rather than the final recovery. Figure 12b

479

demonstrates that imbibition of brine for the surfactant with EO of 2.5 is significantly slower

480

than the one with municipal water and the base surfactant. As discussed in Section 4.2, this

481

might be due to precipitation of surfactant and partial blockage of pores and throats. Even

482

though increasing the ethoxylation degree from 8.2 to 18 induced faster brine imbibition for

483

sandstone rocks as shown in Figure 12d, the final production was not significantly affected

484

by this parameter. To further explore the reasons leading to above-mentioned behaviors,

485

we studied the impact of pore size distribution on capillary desaturation curve (CDC) and

486

oil-brine displacements.

487

Previous investigations have shown that pore size distribution has a significant impact on

488

capillary desaturation and residual nonwetting phase saturation. 61,62 Generally, the water-

489

flood residual oil saturation reduces with increase in capillary number except for its very low

490

values over which capillary forces dominate the displacement process. The threshold beyond

491

which the residual oil saturation becomes sensitive to changes in capillary number can vary

492

significantly depending on pore scale attributes of the medium. The inflection point in CDC

493

for carbonates, with wider pore size distribution, happens at lower capillary numbers than

494

that of the sandstones. These trends are often used for forced waterflooding studies primarily

495

because the spontaneous imbibition tests do not necessarily produce the residual oil satu-

496

ration state in the porous sample. However, we still consider capillary number calculations

497

an appropriate approach to assess the impact of pore size distribution on our spontaneous

498

imbibition experiments. We calculated capillary number for tests in Edwards and Berea rock



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499

samples using Equation 1. The results are presented in Table 8.

500

The data show that reduction in IFT increased the capillary number for imbibition in

501

Berea sandstone only moderately. While for Edwards limestone, the capillary number is

502

increased by more than two orders of magnitude. This is considered to be the main reason for

503

the significant enhancement of recovery from Edwards due to spontaneous imbibition when

504

different surfactant solutions are used. Whereas, in Berea, increasing the capillary number

505

by reducing IFT does not affect the remaining nonwetting phase saturation significantly. In

506

other words, using tap water with no surfactant in sandstone led to similar oil recovery as

507

those of surfactant solutions (see Figure 12). However, a narrower pore size distribution,

508

smaller aspect ratio (3.89 compared to 4.76 ), and lower contact angels (Figure 10) in the

509

sandstone led to greater ultimate oil production as opposed to limestone with wider pore size

510

distribution 61,63,64 (51% oil recovery compared to 45%). This impact is also illustrated in

511

Figure 12 that shows a lower remaining nonwetting phase saturation in sandstones compared

512

to that in carbonates. Even though the Edwards samples had lower permeabilities compared

513

to Berea cores, we believe presence of micro pores improved the rate of oil production in

514

this rock at initial stages. This is attributed to micro pores (Figure 2d) providing a better

515

accessibility for brine to imbibe into a significant number of oil-filled pores at the early stage

516

of the imbibition process. Different minerals could impact the interfacial properties of fluids

517

due to brine/minerals interactions (i.e., alteration in pH and alkalinity of the fluids). This

518

in turn, can change the recovery factors. We measured the oil/brine IFT and CA with and

519

without equilibration of brine with rock samples. It was found that the presence of different

520

minerals in limestone and sandstone rocks did not affect the interfacial properties of nonionic

521

surfactant solutions and crude oil. Equilibrated with limestone samples and unequilibrated

522

tap water samples provided nearly the same dynamic IFT values with crude oil (i.e., 18.88

523

± 0.68 mN/m). Hence, the pore structure of rock samples was found to be more impactful

524

than their mineralogy on surfactant solution/oil displacements. This was expected due to

525

minor interactions of nonionic surfactants with different minerals.


Page 22 of 56

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526

To ascertain that gravity segregation has a negligible impact on imbibition from Berea

527

and Edwards rock samples, we calculated bond number (the ratio of buoyancy to capillary

528

forces) for our experiments. When the value of this dimensionless number is sufficiently low

529

(e.g., ≤ 10−6 ), 65 fluid flow is capillary controlled. 66 Bond number can be calculated from

530

Equation 3: 67

Bo =

4ρgK γ

(3)

531

where K is the intrinsic (absolute) permeability of the porous medium, γ is the interfacial

532

tension, 4ρ is the density difference, and g is the acceleration due to gravity. The calcu-

533

lated bond numbers for our lowest and highest IFT values were 1.31×10−8 and 7.3×10−10

534

indicating that fluid flow took place under capillary dominated displacement regime. It is

535

noteworthy to mention that during production, oil was produced from all sides of the core

536

sample and not just the top side implying that gravity segregation was not significantly

537

impacting oil production.

538

Figures 12e and 12f and Table 7 demonstrate a slight enhancement in oil production from

539

sandstone and limestone samples by increasing the number of methylene groups from 8-10

540

to 11-14. The improvement in oil recovery was in line with the corresponding IFT values.

541

Increase in the lipophilic characteristics of surfactants is expected to induce a minor increase

542

in their surface activity (Cf. Section 4.2).

543

The imbibition experiments with the best surfactant (EO=18, CH2 = 11 − 14), from

544

previous measurements, were extended to the reservoir rock samples. The spontaneous

545

imbibition results obtained using this surfactant were then compared with those of the base

546

surfactant and tap water (see Figure 14). As it is seen in Figure 14, the selected surfactant

547

provided a significantly faster and higher production from reservoir core sample compared

548

with those of the base surfactant and tap water. Utilizing the best surfactant enhanced 23 ACS Paragon Plus Environment


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

549

the oil recovery from reservoir rock sample by 6% compared to that of base surfactant and

550

22% compared to that of tap water without any surfactant. For a tight rock, the presence of

551

poorly connected nanopores can slow down the imbibition of brine into the medium, creating

552

differences in the rate and final production using various surfactants. These results imply

553

that the proposed methodology in this study can potentially be applied on tight samples to

554

screen surfactants for hydraulic fracturing process.

555

4.5.2

556

To conduct reservoir conditions tests, we selected Edwards limestone because of the fact that

557

its mineralogy and spontaneous imbibition trends were similar to those of the reservoir rock

558

sample in this study. The limestone however had a higher permeability that significantly

559

reduced the amount of time needed to perform the tests. Moreover, the unconventional

560

reservoir rock and limestone core samples used in this work have some similarities in pore size

561

distribution with two peaks on very small and very large pore size diameters (see Akbarabadi

562

et al. 60 ).

Forced waterflooding

563

We carried out three sets of primary drainage-imbibition-secondary drainage flow tests on

564

three low-permeability Edwards limestone core samples at reservoir conditions (see Section

565

3.5). These samples were cut from the same block, which was acquired from a quarry in

566

Texas, United States. The physical properties and dimensions of the rock samples are listed

567

in Table 2. Table 6 summarizes the results of the core flooding experiments, which include

568

endpoint relative permeability values, final fluid saturations, and recovery factor percentages

569

for all three steps of flooding. All the forced imbibition experiments were carried out at a

570

brine flow rate of 0.1 cc/min, providing an average capillary number of 1.355×10−6 .

571

Similar to spontaneous imbibition results, in core flooding experiments at reservoir con-

572

ditions (Table 6), the percentage of oil production (due to primary imbibition) increased by

573

5-6% using EO-18 surfactant compared to that of the base surfactant. The increase in oil

574

recovery might be attributed to an instantaneous reduction in IFT. This leads to a rapid


Page 24 of 56

Page 25 of 56

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575

decrease in the threshold capillary pressure in the pore space that directly impacts the order

576

by which pore-scale displacements take place at a fixed brine flow rate (0.1 cc/min), which in

577

turn produces an improved recovery efficiency. Note that during the flowback experiments,

578

the volumes of brine recovered by EO-18 and base surfactant were comparable. These results

579

confirm the relevance of the proposed methodology to screen surfactants and its potential

580

implications for enhancing oil recovery from tight rocks at reservoir conditions.

581

Table 6 also lists the end-point relative permeability data. As expected, with reduction

582

in residual oil saturation from the first waterflood (base surfactant) to the second (EO-18),

583

the end-point water relative permeability increased. However, krw decreased in the third

584

waterflooding test. The variation in end-point relative permeability values may have been

585

caused by the slight differences in the samples used. Moreover, for all the core flooding tests,

586

kro values at the end of the second drainage were lower than that of the first ones. This could

587

be due to the fact that water saturation was not, in two of the cases, reduced to the level

588

reached during the first drainage. Furthermore, the limestone samples may have experienced

589

some degree of wettability alteration due to coming in contact with crude oil. This could

590

potentially reduce oil relative permeability.

591

4.5.3

592

As mentioned previously, the information obtained from bulk analysis such as minimum inter-

593

facial tension have been commonly used as an assessment criterion for surfactant screening

594

during core flooding. 68 However, the results from this study reveal that the duration by

595

which a surfactant reduces the interfacial tension plays an important role in trapping of the

596

oil phase within the pore space. In the case where a fast IFT reduction occurs, local capil-

597

lary pressure reduces spontaneously inside the porous media. This, in-turn, accelerates oil

598

mobilization, as brine is able to overcome the threshold capillary pressure of more pores at

599

the initial steps of invasion leading to more displacement. However, for a surfactant with a

600

gradual partitioning at oil/brine interface, oil fragmentation and capillary pressure reduction

Oil recovery mechanism



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

601

are slower processes. This, indeed, increases the chance of channeling through pore space

602

due to bypassing the entrances with higher threshold capillary pressure and consequently

603

more entrapment of oil phase. Even though, oil/brine interfacial tension will reach a final

604

value after a few hours throughout porous media, the trapped oil globules stay discontinuous

605

within the pore space.

606

In an attempt to test the validity of the suggested mechanism in porous media, first, two

607

sets of experiments were conducted in micromodels. The models were constructed based on

608

Bentheimer sandstone pore/throat configuration and had a porosity of 53%. Two surfactants

609

with similar hydrophobic tail length and different hydrophilic heads (i.e., EO chain length)

610

were selected for these tests. Prior to injection, each model was fully saturated with crude oil

611

to simulate the initial stage in spontaneous imbibition experiments. Thereafter, surfactant

612

solutions were injected with a flow rate of 0.00001 cc/min providing a capillary number

613

close to 10−6 . Figure 15 provides a qualitative observation of oil displacement by surfactant

614

solutions as a function of EO number at residual oil saturation stage. Results from these

615

tests confirm that under the same flow rate, the fluids displacement is also a direct function

616

of dynamic interfacial tension. Surfactant with greater EO and faster oil/brine equilibration

617

displaced more oil from the porous medium and resulted in smaller trapped oil phase. It can

618

be seen from this figure that brine containing EO-7 did not invade many of the pore/throat

619

junctions and bypassed them, despite the fact that EO-7 surfactant had lower final IFT.

620

To further demonstrate the proposed trapping mechanism, we followed the same proce-

621

dure used for spontaneous imbibition tests on two miniature limestone core samples (named

622

Fond du Lac) and then imaged the samples employing a micro-CT scanner. We used core

623

samples with larger pore space (i.e., average pore diameter of 400 micron) to better visualize

624

the fluids configurations. The miniature core samples were 5 mm in diameter and 20 mm

625

in length with average porosity of 20 % and permeability of 400 md. The scanning field of

626

view was a 5 × 5 × 5 mm3 cylinder which was larger than the measured Representative

627

Elementary Volumes (REV) (32.7 mm3 ). 12 wt.% of 1-iodooctane was added as dopant to


Page 26 of 56

Page 27 of 56

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628

the oil phase in order to enhance the X-ray contrast between the fluids in micro-CT im-

629

ages and improve the accuracy of image segmentation procedure. Figure 16 demonstrates

630

that the surfactant with greater EO and faster oil/brine equilibration imbibes to a greater

631

extent and leads to less residual oil phase compared to EO-7. Residual oil saturations and

632

cluster analysis were determined using Avizo software. Recovery factors were calculated as

633

50.50% and 55.22% for imbibition with EO 7 and 18, respectively. Results from these tests

634

show that the above-mentioned mechanism is not limited to specific limestones as analogous

635

trends were observed in the Fond du lac and Edwards limestone with very different rock

636

properties. Figure 17 represents the normalized frequency of residual oil clusters after the

637

spontaneous imbibition experiments. It can be seen that the normalized fraction of smallest

638

globules is larger by around 10% when surfactant with higher ethoxylation degree is used.

639

On the other hand, surfactant solution with EO-7 led to more coalesced clusters in larger

640

volume range. These results show that increasing the hydrophilicity of the surfactant im-

641

proves its fragmentation ability. This is also in line with the suggested mechanism as faster

642

IFT reduction enables the surfactant to break down the oil clusters more effectively.

643

5

644

A new systematic and integrated procedure was introduced to study the influence of sur-

645

factant structures on dynamic interfacial properties inside porous media for oil recovery

646

application. Hydrophobic and hydrophilic parts of POE-type nonionic surfactants were al-

647

tered, while solubilization, emulsification, dynamic IFT and CA, and imbibition behaviors

648

were investigated at both ambient and reservoir conditions. The performances of these sur-

649

factants were compared to that of a base surfactant commercially deployed in the targeted

650

unconventional reservoir. The main conclusions based on our laboratory experiments are as

651

follows:

652

Conclusions

1. Surfactants that reduced the IFT instantaneously were more effective than the ones



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

653

that reduced the IFT to even lower values but over a longer period of time. The highly

654

ethoxylated POE-type surfactant instantaneously reached equilibrium upon the introduction

655

of crude oil to the surfactant solutions, while it did not provide the lowest IFT. This structure

656

was found to be the most effective in enhancing oil recovery.

657

2. Surfactants with greater degree of hydrophilicity were more effective at reservoir

658

conditions as their structures could tolerate higher temperatures. Even though the elongation

659

of EO chains increased the emulsification propensity of surfactants at ambient conditions,

660

no microemuslion was observed at high temperature using reservoir crude oil and tap water,

661

which is advantageous for tight reservoirs.

662

3. Increasing the hydrophilicity of surfactants from low to high range resulted in higher

663

oil recovery during spontaneous and forced imbibition tests. Utilizing the best surfactant

664

increased the oil production from reservoir rock sample by 22% and 6% compared to tap

665

water and base surfactant, respectively.

666

667

4. Spontaneous imbibition behavior of oil/brine in rock samples using different nonionic surfactants was affected more significantly by pore-throat structure than mineral type.

668

5. Direct evidence form visualization at micro scale revealed that the superior recovery

669

factor obtained from surfactant solution with instantaneous oil/brine equilibration was due

670

to its ability to invade larger number of pores/throats within porous media and break down

671

the oil clusters more effectively.

672

Even though the study presented in this work were obtained through conducting exper-

673

iments using different rock types, one should note that in order generalize the results of

674

this study on any combination of crude oil/brine/rock properties further investigations are

675

needed.


Page 28 of 56

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676

6

Acknowledgments

677

We gratefully acknowledge financial support of Hess Corporation and the School of Energy

678

Resources at the University of Wyoming. Graduate students Mohammad Heshmati and

679

Masakazu Gesho of Piri Research Group at the University of Wyoming are thanked for their

680

help with some of the laboratory experiments and image analysis procedures. We would also

681

like to acknowledge Dr. Lin Jiang for his assistance in HRTEM imaging.



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

682

683

684

685

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719

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726

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Evaluation of Surfactants for Oil Recovery Potential in Shale Reservoirs SPE Improved

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769

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789

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Page 38 of 56

Table 1: Dimensions and petrophysical properties of the core samples used in spontaneous imbibition tests. Porosity and permeability were measured using helium porosimeter and permeameter. Samples Avg. Diameter Avg. Length Avg. φ Avg. Kabs cm cm % mD Berea sandstone 2.5 5 23 214 Edwards limestone 2.5 5 20 23 Reservoir rock 3.8 2.7 6.65 0.00381 36

Table 2: Dimensions and petrophysical properties of Edwards limestones used in the core flooding experiments. Values were obtained using core flooding system. Sample no.

Exp.

1 2 3

Base surfactant EO-18 1st EO-18 2nd

Diameter cm 3.770 3.777 3.765

Length cm 15.98 14.80 14.61

Kabs to brine mD 7.98 14.7 13.97

Porosity % 21.05 22.91 21.50

Pore volume cm3 37.55 37.99 34.97

Table 3: Properties of the crude oil used in this study. 39 TAN: Total Acid Number, TBN: Total Base Number. Crude oil properties Density 20 ◦ C (g/cc) 0.81 Viscosity (cp) 2.804 Asphaltene content (wt%) 0.45 TAN (mg of KOH/g) 0.23 TBN (mg of KOH/g) 0.68 Refractive index 1.46


Page 39 of 56

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Table 4: Concentrations of dominant ions in tap water and reservoir brine. 39 Ions N a+ Ca2+ M g 2+ Cl− SO42− N O3−

Tap water Reservoir brine ppm ppm 8 102129 47 19805 14 1509 7 196935 18 10 -

Table 5: Surfactant structures used in this study. Trade name Chemical structure CMC (%Weight) BIO-SOFT N91-2.5 CH3 (CH2 )8−10 (OC2 H4 )2.5 OH 0.005 BIO-SOFT N91-6 CH3 (CH2 )8−10 (OC2 H4 )6−6.5 OH 0.02 BIO-SOFT N91-8 CH3 (CH2 )8−10 (OC2 H4 )8.3 OH 0.02 BIO-SOFT N1-3 CH3 (CH2 )10 (OC2 H4 )3 OH 0.005 BIO-SOFT N1-5 CH3 (CH2 )10 (OC2 H4 )5 OH 0.01 BIO-SOFT N1-7 CH3 (CH2 )10 (OC2 H4 )7 OH 0.01 BIO-SOFT N1-9 CH3 (CH2 )10 (OC2 H4 )9 OH 0.015 BIO-SOFT N-23-3 CH3 (CH2 )11−12 (OC2 H4 )3 OH 0.0005 BIO-SOFT N-23-6.5 CH3 (CH2 )11−12 (OC2 H4 )6.5 OH 0.001 BIO-SOFT EC-639 CH3 (CH2 )11−13 (OC2 H4 )8.2 OH 0.001 BIO-SOFT N-25-3 CH3 (CH2 )11−14 (OC2 H4 )3 OH 0.001 BIO-SOFT N-25-7 CH3 (CH2 )11−14 (OC2 H4 )7.25 OH 0.001 BIO-SOFT N-25-9 CH3 (CH2 )11−14 (OC2 H4 )9 OH 0.002 Poly (ethylene glycol) (18) tridecyl ether CH3 (CH2 )12 (OC2 H4 )18 OH 0.015



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Page 40 of 56

Table 6: Fluid saturations, end-point relative permeabilities, and recovery factors obtained at the end of each step of core flooding at reservoir conditions.

1st drainage Imbibition 2nd drainage

Sw 0.233 0.601 0.231

Base surfactant krw kro RF(%) 0.5 0.084 47.98 0.29 61.56

EO-18 (1st experiment) Sw krw kro RF(%) 0.234 0.41 0.654 0.12 54.83 0.279 0.31 57.34

EO-18 (2nd experiment) Sw krw kro RF(%) 0.238 0.45 0.643 0.065 53.15 0.270 0.24 58.01

Table 7: Impact of POE chain length on t∗ (i.e., the required time for IFT to reach half of its value) and oil recovery. No. of CH2 No. of EO t∗ (minute) Recovery from Edwards (%) 2.5 16.5 42.69± 1.37 8-10 6 12.3 44.94± 1.16 8 11.6 45.41± 1.5 3 23 41.69± 2.29 11-14 7.25 9.3 45.7± 1.16 8.2 7.83 46.78± 1.24 18 3.5 48.8± 1.61 Base surfactant 15.66 43.87± 1.5

Table 8: Calculated capillary numbers from spontaneous imbibition results. IFT Capillary number

Edwards limestone Tap water (18.88 mN/m) 8.34E-08

Edwards limestone Surfactant solution (1 mN/m) 1.57E-06

Berea sandstone Tap water (18.88 mN/m) 4.17E-07


Berea sandstone Surfactant solution (1 mN/m) 7.87E-06

Page 41 of 56

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Clays with interaparticle pores

Calcite

Dolomit e

Interparticle pores

Quartz Feldspar

(a)

(b)

Figure 1: (a) SEM micrographs in BSE mode (1 kV voltage, 100 pA current, and 25 nm image resolution), (b) Elemental maps of reservoir rock sample using EDS (10 kV voltage, 3200 nA current, and 50 nm image resolution). 40



(a) D.= 2 mm, Res. = 1.0 µm

(b) D.= 3 mm, Res. = 1.5 µm

10

Edwards Berea 8

Normalized volume (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Micro pores

6

4

2

0 0

100

200

300

400

Diameter( m)

(c)

(d)

Figure 2: Two dimensional visualization of pore space of (a) Edwards limestone and (b) Berea sandstone rock samples and (c) pore size distribution of Edwards limestone and Berea sandstone rock samples. SEM micrographs in BSE mode of Edwards limestone sample (d) in pixel resolution of 0.5µm. (D.: Diameter, Res.: Resolution) . 42 ACS Paragon Plus Environment

Page 42 of 56

Page 43 of 56

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


H H

CH2 H3C

O

CH2

C C O H H

n

H y

Figure 3: General structure of the surfactants investigated in this work (n=number of ethylene oxide molecules, y= number of alkyl molecules).

(a)

(b)

Figure 4: Examples of images used for (a) dynamic and (b) static contact angle measurements.



1 2 0

C H 3 (C H 2 )

1 1 0

C lo u d p o in t te m p e r a tu r e ( ° C )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 44 of 56

y

y = 8 -1 0 y = 1 0 y = 1 1 -1 4

1 0 0 9 0 8 0 7 0 6 0 5 0 4 0 3 0 2 0 2

4

6

8

1 0

1 2

1 4

1 6

1 8

N u m b e r o f P O E Figure 5: Effect of hydrophilic and hydrophobic chain length on cloud point temperature at 6840 psi (y= number of alkyl molecules)


Quizix 5000

Brine Pump (P1)

Quizix 5000

Quizix 5000

Oil Pump (P2)

Quizix 5000

RD

RD

RD

RD

Figure 6: Schematic diagram of the core flooding setup.

ACS Paragon Plus Environment

45 Large Oven

Large Oven

T

PT P

Manual Overburden Pressure Pump (P4)

Large Oven

Pressure array

Core holder

PT P

Quizix 5000

Quizix 5000 RD Back Pressure Pump (P3)

: Oven

: Three-way manual valve

: 1/16 in. tubing : Oil line : Brine line : Outlet line : Pressure gauge

: Graduated burette

Back Pressure Regulator valve

RD : Rupture Disk

: Liquid accumulator

T : Thermocouple

: Three-way Vindum valve

: Pressure Transducer

RD

PT

DPT : Differential Pressure Transducer

: Back Pressure Relief valve

: Two-way manual valve

Cooling bath

: Spiral line

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 Graduated Burette

Page 45 of 56 Industrial & Engineering Chemistry Research


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

CH3(CH2)n , n = 8-10

Base S. 2.5

25°C

6 .25

8.3 (EO)

CH3(CH2)n , n = 10

25°C

Page 46 of 56

CH3(CH2)n , n = 8-10 80°C

Base S. 2.5

6 .25

8.3 (EO)

CH3(CH2)n , n = 10

80°C

Micelles

Base S. 3

5

7

9 (EO)

Microemulsion

Base S. 3

5

7

9 (EO)

CH3(CH2)n , n = 11-14 25°C

CH3(CH2)n , n = 11-14 80°C

Base S. 3

Base S. 3

7.25

8.2 18 (EO)

7.25

8.2 18 (EO)

Figure 7: Phase behavior tests with crude oil and surfactant solutions (0.1wt.%) and HRTEM micrographs of microemulsion phase at ambient temperature (a),(c),(e) and 80 ◦ C (b),(d),(f) for different lengths of ethylene oxide and alkyl chain. (EO: number of ethylene oxides)


Page 47 of 56

1 2

1 2 3

(C H 2

B a s E O E O E O

1 0

IF T (m N /m )

8

C H

)n - n = 8 -1 0 e s - 2 - 6 - 8

u rfa c ta n t .5 .2 5 .3 E O

- 2 .5

E O

- 6 .2 5

E O

- 8 .3

6

1 0

)n - n = 1 0 2

8

B a s e s u rfa c ta n t 6

4

E O

- 7

2

E O

- 9

4

2

(C H 3

B a s e s u rfa c ta n t E O - 7 E O - 9

IF T (m N /m )

C H

B a s e s u rfa c ta n t 0 0 0

2 0

4 0

6 0

8 0

1 0 0

0

2 0

1 2 0

4 0

6 0

(a)

1 0 0

1 2 0

(b)

1 8

1 2

C H 1 6

(C H 3

L o w

E O

- 3

e s e -

C H

d iu m r a n g e s u rfa c ta n t 3 7 .2 5 8 .2

1 0 8

8

)n - n = 1 1 -1 4 2

to a s e O O O -

h ig h r a n g e s u rfa c ta n t 8 .2 1 5 1 8

6


(C H 3

M e d iu m B E E E

1 0

IF T (m N /m )

1 2

)n - n = 1 1 -1 4 2

to m B a E O E O E O

1 4

IF T (m N /m )

8 0

T im e ( m in u te )


4

E O

- 1 8

E O

- 1 5

4

E O

- 7 .2 5

E O

- 8 .2


2

E O

0

0 0

2 0

4 0

6 0

8 0

1 0 0

1 2 0

0

2 0

4 0


6 0

8 0

1 0 0

- 8 .2 1 2 0


(c)

(d)

1 2

1 2

E O

- 8

E O

B a s e s u rfa c ta n t C H 3(C H 2)n - n = 8 -1 0

1 0

C H 3

(C H 2

1 0

)n - n = 1 1 -1 4

- 9 B a s e s u rfa c ta n t C H 3(C H 2)n - n = 1 0 C H 3

(C H 2

)n - n = 1 1 -1 4

8

IF T (m N /m )

8

IF T (m N /m )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60



B a s e s u rfa c ta n t

4

6

4

n = 1 0

n = 8 -1 0 2

2

n = 1 1 -1 4

n = 1 1 -1 4 0

0 0

2 0

4 0

6 0

8 0

1 0 0

1 2 0

0

2 0

4 0


6 0

8 0

1 0 0

1 2 0


(e)

(f)

Figure 8: Effect of hydrophilic (a),(b),(c),(d) and hydrophobic chain lengths (e),(f) of surfactant molecules on dynamic interfacial tensions at ambient conditions. (EO: number of ethylene oxides). IFT for tap water/crude oil=18.88 ± 0.68 mN/m



1 8

1 8

B a s e s u rfa c ta n t

1 6 1 4

R e s . c o n d itio n s A m b . c o n d itio n s

R e s . c o n d itio n s

C H

1 6

3

E O

)n - n = 1 0


IF T (m N / m )

IF T (m N / m )

2


1 2

1 0

(C H - 7

1 4

1 2

1 0

8

8

A m b . c o n d itio n s 6

6 4

4 2

2

A m b . c o n d itio n s

0

0 0

5

1 0

1 5

2 0

2 5

3 0

3 5

T im e ( m in u t e )

4 0

4 5

5 0

0

(a)

1 8

C H E O

3

(C H 2

)n - n = 8 -1 0

1 5

2 0

2 5

3 5

4 0

4 5

5 0

(b) C H 3

E O

(C H 2

)n - n = 1 1 -1 4

- 1 8 R e s . c o n d itio n s A m b . c o n d itio n s

1 4 1 2

IF T (m N / m )

1 2

3 0


1 6


1 0

R e s . c o n d itio n s 8 6

1 0

- 8

1 4

1 0

5

1 8

1 6

IF T (m N / m )

8 6


A m b . c o n d itio n s 4

4 2

2

A m b . c o n d itio n s

0

0 0

5

1 0

1 5

2 0

2 5

3 0

3 5


4 0

4 5

5 0

0

5

1 0

1 5

2 0

(c)

2 5

3 0


3 5

4 0

4 5

5 0

(d) 1 8

B a E O E O E O

1 6 1 4 B a s e s u rfa c ta n t

1 2

se su rfa c ta n t -7 -8 -1 8

E O -7

IF T (m N / m )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 48 of 56

1 0 8

E O -8 6 4

E O -1 8 2 0 0

5

1 0

1 5

2 0

2 5

3 0


3 5

4 0

4 5

5 0

(e)

Figure 9: Effect of temperature (a), (b), (c), (d) and hydrophilic chain length (e) on dynamic IFT of the selected surfactant solutions/crude oil at reservoir conditions (6840 psi and 120 ◦ C). EO: number of ethylene oxides


Page 49 of 56

1 0 0

1 0 0

E d w a r d s lim e s to n e C H 3(C H 2)n-O (C H 2C H 2

B e re a S a n d s to n e C H 3(C H 2)n-O (C H 2C H

O )yH

2

O )yH

8 0

S ta tic c o n ta c t a n g le ( ° )

S ta tic c o n ta c t a n g le ( ° )

8 0

6 0

4 0

2 0

6 0

4 0

2 0

0

0 T a p w a te r

y = 1 8

y = 6 .2 5 n = 8 -1 0

n = 1 2

T a p w a te r

y = 1 8

y = 6 .2 5 n = 8 -1 0

n = 1 2

Figure 10: Effect of surfactant structure on static contact angle on Edwards limestone and Berea sandstone at ambient conditions.

9 0

9 0

C H

8 0

3

(C H 2

)n-O (C H 2

C H 2

O )yH

C H

8 0

7 0

R e c e d in g c o n ta c t a n g le ( ° )

A d v a n c in g c o n ta c t a n g le ( ° )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


6 0 5 0 4 0 3 0 2 0 1 0

3

(C H 2

)n-O (C H 2

C H 2

O )yH

7 0 6 0 5 0 4 0 3 0 2 0 1 0

0

0 T a p w a te r

B a s e S .

y = 6 .2 5 n = 8 -1 0

y = 7 n = 1 0

y = 8 .3 n = 8 -1 0

y = 1 8 n = 1 2

T a p w a te r

B a s e S .

y = 6 .2 5 n = 8 -1 0

y = 7 n = 1 0

y = 8 .3 n = 8 -1 0

y = 1 8 n = 1 2

Figure 11: Effect of surfactant structure on dynamic contact angle at reservoir conditions.


Industrial & Engineering Chemistry Research 5 5

5 5

4 5

4 5

5 0

C H 3

(C H

3 5 3 0

E d w a rd s C a rb o n a te

2 5 2 0

C H

1 5

3

(C H

)n - n = 8 -1 0 2

T a p B a s E O E O E O

1 0 5 0

0 .0 1

0 .1

1

1 0

T im e ( h o u r )

2

)n - n = 8 -1 0


4 0

O il r e c o v e r y ( % )


B e re a S a n d s to n e

5 0

4 0

3 5 3 0

w a te r e s u rfa c ta n t - 2 .5 - 6 .2 5 - 8 .3

2 5 2 0 1 5

w a te r e s u rfa c ta n t - 2 .5 - 6 .2 5 - 8 .3

1 0 5 0

1 0 0

0 .1

1

5 5

4 5

4 5

5 0

C H 3

(C H

3 0


2 5 2 0

C H

1 5

3

(C H 2

)n - n = 1 1 -1 4

T a p B a s E O E O E O E O

1 0 5 1 0

3 5

w a te r e s u rfa c ta n t - 3 - 8 .2 - 1 8

2 5 2 0 1 5

w a te r e s u rfa c ta n t - 3 - 7 .2 5 - 8 .2 - 1 8

1 0 5 0

0 .1

1

T im e ( h o u r )

(c)

(d)

5 5

5 5

4 5

4 5

5 0


5 0

E O

4 0

3 5 3 0 2 5


1 5

E O

2 0 1 0 5

- 8 .3 T a p w a te r B a s e s u rfa c ta n t (C H 2)n - n = 8 -1 0 (C H

0 .1

1

T im e ( h o u r )

1 0

2

)n - n = 1 1 -1 4 1 0 0


4 0

0

1 0 0

)n - n = 1 1 -1 4

3 0

1 0 0

T im e ( h o u r )

2


4 0

3 5



4 0

1

1 0


5 0

0 .1

1 0 0

(b)

5 5

0

1 0

T im e ( h o u r )

(a)


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 50 of 56

- 8 .3 T a p w a te r B a s e s u rfa c ta n t C H 3(C H 2)n - n = 8 -1 0

3 5

C H 3

(C H 2

)n - n = 1 1 -1 4

3 0 2 5 2 0 1 5 1 0 5 0

0 .1

1

(e)

1 0

T im e ( h o u r )

1 0 0

(f)

Figure 12: Effect of increasing hydrophilic (a),(b), (c), (d) and hydrophobic (e), (f) chains on spontaneous imbibition of surfactant solutions in saturated limestone and sandstone rock samples at ambient conditions. (EO: number of ethylene oxides)


Page 51 of 56

I ti

II

𝛾 t, mN/m

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


t1/2

tm

III 𝛾m

Log t

Figure 13: Dynamic interfacial tension regions versus time: region I, induction; region II, rapid fall region; and region III, mesoequilibrium. Taken from Hau and Rosen (1988) 49



6 0 5 5

R e s e r v o ir r o c k

5 0

T a p w a te r B a s e s u rfa c ta n t E O = 1 8 , C H 2= 1 1 -1 4

4 5


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 52 of 56

4 0 3 5 3 0 2 5 2 0 1 5 1 0 5 0

0 .1

1

1 0

T im e ( h o u r )

1 0 0

1 0 0 0

Figure 14: Spontaneous imbibition in saturated reservoir core samples at ambient conditions using tap water, base and EO-18 surfactants.


Page 53 of 56

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


Time

Time

(a) Sor - EO:7

(b) Sor - EO:18

(c)

(d)

Figure 15: Fluid occupancies and displacement patterns of surfactant solutions with EO of (a,c) 7 and (b,d) 18. The flow direction is from left to right in all images. (red: oil, blue: brine, white: grain).



1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

(a)

Page 54 of 56

(b)

(c)

(d)

Figure 16: Two- and three-dimensional views of the fluid occupancy at the end of spontaneous imbibition tests for surfactant solutions with (a,c) EO-7, (b,d) EO-18. (red: oil, blue: brine, gray: grain).


Page 55 of 56

70 50

EO:7 EO:18

30

Normalized count (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60


10 7 5

3

1

0.7 0.5

0.3

10

100

1000

10000

100000

3

Volume ( m )

Figure 17: Normalized count of oil clusters versus cluster volume.


1000000


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Time

Page 56 of 56

Time

(a) Sor - EO:7

(b) Sor - EO:18

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