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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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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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(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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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
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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
286
the solubilization capacity of the surfactants in aqueous phase. For a very short polar head,
287
dissolution in water is limited as hydration forces are chiefly responsible for solubility. As a
288
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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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-
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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
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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,
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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
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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
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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
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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.
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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
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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
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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
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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
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Industrial & Engineering Chemistry Research
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
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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.
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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.
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683
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685
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alteration in stimulation fluids and the potential for surfactant EOR in unconventional
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(34) Alvarez, J. O.; Schechter, D. S. Wettability Alteration and Spontaneous Imbibition in
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characterization of transport properties International Journal of Coal Geology 2015,
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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
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Industrial & Engineering Chemistry Research
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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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
40 ACS Paragon Plus Environment
Berea sandstone Surfactant solution (1 mN/m) 7.87E-06
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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
Industrial & Engineering Chemistry Research
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
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(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
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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
Industrial & Engineering Chemistry Research
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.
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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)
44 ACS Paragon Plus Environment
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
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)
46 ACS Paragon Plus Environment
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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
B a s e s u rfa c ta n t 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 )
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
B a s e s u rfa c ta n t 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
T im e ( m in u te )
6 0
8 0
1 0 0
- 8 .2 1 2 0
T im e ( m in u te )
(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
Industrial & Engineering Chemistry Research
B a s e s u rfa c ta n t 6
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
T im e ( m in u te )
6 0
8 0
1 0 0
1 2 0
T im e ( m in u te )
(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
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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
R e s . c o n d itio n s
IF T (m N / m )
IF T (m N / m )
2
R e s . c o n d itio n s A m b . c o n d itio n s
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
T im e ( m in u t e )
1 6
R e s . c o n d itio n s A m b . c o n d itio n s
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
R e s . c o n d itio n s
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
T im e ( m in u t e )
4 0
4 5
5 0
0
5
1 0
1 5
2 0
(c)
2 5
3 0
T im e ( m in u t e )
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
T im e ( m in u t e )
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
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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
Industrial & Engineering Chemistry Research
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.
49 ACS Paragon Plus Environment
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
T a p B a s E O E O E O
4 0
O il r e c o v e r y ( % )
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
E d w a rd s C a rb o n a te
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
B e re a S a n d s to n e
5 0
E O
4 0
3 5 3 0 2 5
E d w a rd s C a rb o n a te
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
O il r e c o v e r y ( % )
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
T a p B a s E O E O E O
4 0
3 5
O il r e c o v e r y ( % )
O il r e c o v e r y ( % )
4 0
1
1 0
B e re a S a n d s to n e
5 0
0 .1
1 0 0
(b)
5 5
0
1 0
T im e ( h o u r )
(a)
O il r e c o v e r y ( % )
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
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- 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)
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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
Industrial & Engineering Chemistry Research
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
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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
O il r e c o v e r y ( % )
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
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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.
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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
Industrial & Engineering Chemistry Research
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).
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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)
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(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).
54 ACS Paragon Plus Environment
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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
Industrial & Engineering Chemistry Research
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.
55 ACS Paragon Plus Environment
1000000
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
Time
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Time
(a) Sor - EO:7
(b) Sor - EO:18
Table of Contents Graphic
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