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Silica Nanofluids in an Oilfield Polymer Polyacrylamide: Interfacial Properties, Wettability Alteration and Applications for Chemical Enhanced Oil Recovery Tushar Sharma, Stefan Iglauer, and Jitendra S. Sangwai Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.6b03299 • Publication Date (Web): 08 Nov 2016 Downloaded from http://pubs.acs.org on November 12, 2016

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Industrial & Engineering Chemistry Research

Research article

Silica Nanofluids in an Oilfield Polymer Polyacrylamide: Interfacial Properties, Wettability Alteration and Applications for Chemical Enhanced Oil Recovery

Tushar Sharmaa, b, Stefan Iglauerc, Jitendra S. Sangwaia,*

a

Enhanced Oil Recovery Laboratory, Department of Ocean Engineering, Indian Institute of Technology Madras, Chennai 600 036, India b

Department of Petroleum Engineering, Rajiv Gandhi Institute of Petroleum Technology, Rae Bareli 229316, India

c

Department of Petroleum Engineering, Curtin University, 26 Dick Perry Avenue, 6151 Kensington, Australia

*

Corresponding Author. Tel.: +91-44-2257-4825 (Office); fax: +91-44-2257-4802. E-mail address: [email protected] (Jitendra S. Sangwai). 1 ACS Paragon Plus Environment


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Highlights 1. Application of nanotechnology in oilfield applications envisaged. 2. Nanofluid show quality enhancement in interfacial properties of P/SP flooding schemes. 3. Nanofluid show potential for high temperature oil recovery applications. 4. Wettability of sand-pack has been modified (intermediate to water-wet) due to nanofluid. 5. Proposal of nanofluid for wettability alteration and oil recovery applications.

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Abstract Oil production from matured crude oil reservoirs is still associated with low recovery factors. Chemical enhanced oil recovery (EOR) is one of the techniques which can significantly improve the recovery factor of the trapped oil. This is mainly achieved by lowering the interfacial tension (IFT) of the crude oil-brine/aqueous chemical, and increase in the viscosity of the injected fluid. Nanofluids have demonstrated potential in this respect, and we thus examined how such nanofluids behave when formulated with standard oilfield polymers, with a particular focus on their EOR efficiency. In this work, silica (SiO2) nanofluids with (NSP) or without (NP) surfactant (sodium dodecyl sulfate) added, and with varying nanoparticle concentration were formulated with polyacrylamide (PAM), and characterized by DLS and ζ-potential measurements. These nanofluids were then tested in EOR core-flood experiments. Various studies involving the stability and viscosity of nanofluids, interfacial tension of the nanofluidcrude oil system, their effect on wettability alteration and efficiency for EOR studies as a function of temperature have been reported. The efficiency of the nanofluid systems for IFT reduction and EOR has also been compared with the conventional polymer (P) and surfactantpolymer (SP) flood schemes. The SiO2 nanofluids significantly increased oil recoveries, particularly at higher temperatures; mainly due to IFT reduction, fluid viscosity increase and wettability alteration (from intermediate-wet to strongly water-wet). We conclude that SiO2 nanofluids can potentially be attractive EOR chemicals, particularly for wettability alteration operations and high temperature applications.

Keywords: Enhanced Oil Recovery; Interfacial Tension; Nanofluid; Nanoparticle; Polymer; Surfactant.



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1. Introduction The importance of crude oil and natural gas for the economic development of the world is indisputable, and demand is expected to grow in the near future. However, at the current stage, most of the world’s oilfields have started showing depletion in oil production while leaving approximately two-thirds of the oil within the reservoirs.1 Various methods are typically employed during the productive life of a crude oil reservoir. These include secondary oil recovery methods such as water flooding and enhanced oil recovery (EOR) techniques. Water flooding is the preferred secondary recovery method due to availability of water in abundance and fewer environmental issues.2 Technically, during water flooding the crude oil is swept towards the production well without affecting the physico-chemical properties of the oil or rock. The oil recovery factor of the water flooding process is, however, typically low ∼29%.3 One key reason for the low efficiency of water flooding is the poor mobility ratio between the injected water and the crude oil. Subsequent to water flooding, various EOR techniques, such as chemical EOR, thermal EOR, microbial EOR, and gas injection EOR, are employed depending upon the nature of the reservoir. Out of these EOR methods, chemical EOR methods are one of the most promising methods for conventional crude oil reservoirs due to their improved recovery factor.4-6 Chemical methods primarily include the use of polymer (P), surfactant-polymer (SP), and alkalisurfactant-polymer (ASP) flooding and are applied to enhance the oil recovery by reducing the interfacial tension (IFT) between the crude oil-water present within the reservoir.7,8 Chemical EOR methods, although they have developed over the years, need improvement for their application

towards

complex

reservoir

conditions,9,10

and

for

improved

reservoir

characterization.11 Nanotechnology helps to improve the performances of various processes by exploiting the properties of various nanoparticles which typically have the dimensions of the order of 100 4 ACS Paragon Plus Environment

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nm or less. Nanoparticles have a larger surface area per unit volume than the bulk material. They can also be used in the form of nanofluids for various industrial applications. Nanofluids are kinetically stable dispersions of nanoparticles in various base fluids, such as water, polymeric solutions, glycols, or alcohols. Such nanofluids offer potential use for various applications, such as in high temperature operations,12,13 asphaltenes inhibition,14 wettability alteration,15,16 and in oil recovery enhancement processes.17-24 Some other advantages associated with the use of nanofluids for oil recovery are: stable rheological properties of the base fluids, reduction in the IFT of the crude oil-water system, and altering the wettability of the reservoir rock.19,24-26 When compared to the base fluid, nanofluids are better structured, and can spread over and wet the rock surfaces more effectively.27 Zhi-yong et al.28 reported that the use of TiO2 nanofluid in water increased the viscosity of water providing favorable mobility ratios. The improved mobility ratio then resulted in better macroscopic displacement efficiency,29 and also improved pore-scale microscopic displacement.30 Bayat et al.31 concluded that the use of water-based Al2O3, TiO2, and SiO2 nanofluids significantly reduced the IFT between crude oil and water, and consequently increased the additional oil recovery from a limestone reservoir. Adsorption experiments with lipophobic and hydrophilic polysilicon nanoparticles (ranging in size from 10 to 500 nm), were conducted to investigate the wettability alteration efficiency with respect to a sandstone surface. The experiments revealed that the nanoparticles significantly changed the wettability of the sandstone surface, which resulted in improved oil recovery.32 Furthermore, Ehtesabi et al.33 have developed an inexpensive and environmental friendly TiO2 nanofluid by mixing titanium tetraisopropoxide, H2O2, and H2O for heavy oil recovery from sandstone reservoirs, and Al-Anssari et al.24 recently showed that silica nanofluid can efficiently alter the wettability of oil-wet calcite surfaces to strongly water-wet. 5 ACS Paragon Plus Environment


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The performance of nanofluids can further be improved by adding polymers or surfactants to provide superior stability and with improved properties such as viscosity, IFT, and wettability.34 Nanoparticles in combination with surfactants may form nanoparticle-surfactant multilayers, which can significantly reduce IFT and alter the system to more water-wet.35 Suleimanov et al.36 carried out EOR experiments with nanofluids of 70-150 nm ferrous metal nanoparticles in water formulated with an anionic surfactant, sulfanole-alkyl aryl sodium sulfonate, and observed an increase in oil recovery efficiency by 35% (when compared to the simple surfactant system). Srinivasan and Shah37 investigated the viscosity and IFT reduction of heavy oil in the presence of a surfactant-stabilized nanofluid containing CuO nanoparticles. CuO nanoparticles exhibited maximum viscosity reduction in heavy oil as compared to surfactantstabilized fluid only. IFT of heavy oil-water has also been reduced substantiality in the presence of CuO nanoparticles. Sedaghat et al.38 used a micromodel set-up to conduct several flooding experiments to monitor the effect of nanoparticles (SiO2 and TiO2) on wettability alteration in the presence of partially hydrolyzed polyacrylamide (HPAM) and surfactant (sodium dodecyl sulfate, SDS). Recently, we also observed that the synergism between nanoparticles with polymer (polyacrylamide, PAM) and surfactant (SDS) led to the development of stable Pickering emulsions (these were stable for more than three weeks) and, when used for EOR, these emulsions provided cumulative oil recovery of around 60-65% from representative Berea sandstone cores.22,39 In spite of these studies on the use of nanofluids for EOR applications, there is a serious lack of data with respect to nanoparticle synergisms with oilfield surfactants and polymers suitable for EOR. We thus formulated SiO2 nanofluids (with varying nanoparticle (N) concentrations: 0.5, 1.0, 1.5, and 2.0 wt%) in base fluids containing aqueous oilfield polymer (P) polyacrylamide (PAM) or surfactant-polymer (SP) system with SDS as surfactant. The use of 6 ACS Paragon Plus Environment

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PAM/SDS-PAM aqueous solutions as base fluids for nanofluid formulation serves two main purposes. Firstly, PAM provides improved dispersion stability for nanoparticles at reservoir conditions, and secondly, the nanoparticle-surfactant combination provides IFT reduction between crude oil and the injected fluids, in addition to providing better mobility ratios. The nanofluids in P (PAM) and SP (SDS-PAM) are henceforth referred to as NP and NSP nanofluid systems. The performance of nanofluids was then compared to conventional polymer and surfactant-polymer flood schemes for enhanced oil recovery efficiency. To the best of our knowledge, this is one of the first attempts to develop SiO2 nanofluids in an oilfield polymer PAM with SDS system for EOR application.

2. Experimental methodology 2.1. Materials Hydrophilic SiO2 nanoparticles (purity 99.5%) of ~15 nm size were supplied by Sisco Research Laboratories, India. PAM (30-35% degree of hydrolysis) with 98% purity in powder form was supplied by SNF Floerger, India. SDS (purity 90%) was obtained from Ranbaxy Fine Chemicals Limited, India. The crude oil was supplied by Oil India Limited (OIL), Assam, India and used for the EOR flooding experiments. The physical properties of the crude oil (including SARA, density, and viscosity) are given in Table 1.40 Deionized water was obtained from Millipore® Elix-10 purification apparatus and used to prepare the fluid samples. Synthetic brine containing 36100 mg/L of sodium chloride (purity 98%) was used for the brine and chase water floods. The properties of the various fluids used in this study and the nomenclature we use in this paper are also tabulated in Table 1.



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2.2. Nanofluid preparation SiO2 nanofluids have been prepared using various SiO2 nanoparticle concentrations (0.5, 1.0, 1.5, and 2.0 wt%, cp. Table 1). However, the use of deionized (DI) water as base fluid was unsuccessful due to the settlement of nanoparticles within 8-10 hours after preparation. Hence, a dispersion agent is necessary; and polyacrylamide (PAM) - which is a well-known oilfield polymer - was used as a dispersant at a concentration of 1000 ppm in DI water (a typical concentration of PAM used in EOR chemicals).22,41 Two types of nanofluids were prepared, one with nanoparticles (N) dispersed only in the aqueous PAM solution (NP), and the other with aqueous surfactantpolymer (NSP) formulations. The NP nanofluids were prepared by first dissolving 1 gm of PAM in 1000 ml of DI water (which results in a 1000 ppm of PAM aqueous solution (P)) followed by stirring at 600 rpm for 8 hours for homogenization. Subsequently, selected amounts of SiO2 nanoparticles (to achieve the prescribed SiO2 concentrations) were added to the aqueous PAM solution, and the formulations were sonicated for 2-3 h in a sonication bath (Ultrasonics Corporation, USA) at 25 Hz frequency. Ultrasonication enhances homogenization and stabilization of nanoparticle dispersions.24,42 The NSP nanofluids were prepared by adding SDS in powder form to the NP nanofluids, followed by another hour of homogenization. SDS concentration of 0.14 wt% was used, which corresponds to the critical micelle concentration (CMC) of aqueous 1000 ppm PAM solution. This CMC value was determined by surface tension measurements using varying SDS concentrations in aqueous 1000 ppm PAM solutions, the detailed procedure are described in section 2.3.1.


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2.3. Nanofluid characterization 2.3.1

IFT measurements IFTs of the crude oil-nanofluid systems have been measured with a dynamic tensiometer

(DCAT 11EC, Data Physics®, Germany) using the Wilhelmy plate method. Detailed information on the experimental method used for IFT measurements for crude oil-water system has been reported in our earlier research work.40 Being the lightest, crude oil overlays the nanofluid in a sample cup during IFT measurement. The sample cup together with the crude oil-nanofluid system was kept in a transparent chamber attached with the temperature sensor in the tensiometer apparatus. The plate submerges and locks at the interface created between the immiscible crude oil and nanofluid phases. The data was analyzed automatically by the in-built software SCAT (Data Physics®, Germany). Sample cup and plate were carefully cleaned and dried before each IFT measurement. Specifically, we measured IFT for the crude oil-P solution; crude oil-SP solution; crude oil-NP nanofluid, and crude oil-NSP nanofluid systems.

2.3.2

Viscosity measurements The nanofluid viscosities were measured with a rheometer (MCR-52, Anton Paar®,

Physica, Austria) equipped with a temperature unit (Peltier system), thermal jacket, and circulation pump (ESCY IC 201) to heat and control the temperature. The solution/nanofluid sample was placed in the measuring cylinder surrounded by the thermal jacket for sufficient time at the test temperature so as to be thermally equilibrated. The viscosity measurements were then conducted for the shear rate range 1.0 to 1000 s-1, however, for simplicity we only report nearzero shear viscosity at 1.5 s-1 shear rate. Each measurement has been repeated at least three times to confirm the reproducibility; with the uncertainty found to be of the order of ±1 to 6% of the reported value. 9 ACS Paragon Plus Environment


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2.3.3

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Zeta potential and particle size measurements ζ-potential and size measurements of nanoparticle aggregates (in nanofluid) were carried

out by dynamic light scattering (DLS) using a particle size analyzer (SZ-100, Nanopartica, Horiba Scientific®, Singapore). The measurements were conducted at 25 °C using 173o detector scattering angle. The nanofluid samples were placed in a small cuvette that was housed inside the instrument to measure the Brownian motion of the nanoparticles through the fluctuations of an illuminated laser beam; from this movement data particle sizes and ζ-potentials were calculated.

2.4 EOR experiments 2.4.1

XRD and SEM measurements Dry silica sand of 0.25-0.42 mm grain size was used for EOR experiments. Size of sand

particles was studied using a scanning electron microscope (SEM, Quanta 450 from FEI, image processor up to 6144 x 4096 pixels). The mineralogical composition of the sand used for the EOR experiments was measured by XRD (using an X-Ray Diffractometer D8 Advance, Bruker, India). The mineral content of sand utilized in the present study is provided in Figure 1. The sand consisted of quartz (88 wt%), kaolinite (7 wt%), feldspar (3 wt%), and chlorite (2 wt%). Nanoparticles may aggregate and form clusters of larger size in the aqueous PAM phase, and these clusters may show retention on sand during flooding. Hence, SEM analysis is required to visualize the structure of these nanoparticle clusters and their deposition in sand. Thus, a layer of flooded sand was attached to an aluminum stub and gold coated for SEM examination (with a ZEISS® Ultra-55, Germany, SEM instrument).


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2.4.2 EOR set-up and flooding procedure 2.4.2.1 EOR set-up The apparatus used for the EOR experiments is shown in Figure 2. The set-up consists of a syringe pump, sand-pack holder, water circulator, and fluid accumulators. The syringe pump is a displacement pump (Teledyne Isco®, model 500D, USA), which was used to inject the different fluids into the sand-pack. The cylindrical sand-pack holder (5.25 cm diameter and 30 cm length) was manufactured by Aries Engineers, Mumbai, India. The holder housed the synthetic sand-pack, which was prepared by compact packing of dry sand together with water.43 The petrophysical properties of the sand packs are listed in Table S1 (supporting information). A water circulator (Brookfield TC-650, USA) pumped hot water through the sand pack’s heating jacket to heat the sand-pack at test temperature for EOR tests (at 30 and 90 oC). Pore volumes (PV), porosity and saturations were measured by volume balance, and permeability by brine injection at constant flow rate (20 mL/h), pressure drop measurements across the sand pack, and application of Darcy’s law (Table S1, supporting information). The sand-packs were highly reproducible with porosity of 29.77% ± 1.34%, and brine permeability of 1006 mD ± 86.50 mD.

2.4.2.2 EOR experimental procedure Firstly, brine at 20 ml/h was injected (also known as pre-flush) in sand-pack to create the condition of uniform saturation. Brine injection also creates a pressure difference (∆p) across sand-pack and its value was measured through a pressure gauge as shown in Figure 2. Flow rate of brine through the sand-pack was measured manually (volume out/min) at the outlet of the holder and used along with ∆p to determine the absolute permeability (kabs) of sand-pack (see Table S1, supporting information) using Darcy’s law. Sand-pack mimics a reservoir rock of fair porosity and permeability (see Table S1, supporting information). Subsequently, crude oil was



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injected (at 20 mL/h) into the brine saturated sand pack until water production ceased. The amount of water produced at this stage is equal to the amount of oil in the sand pack referred to as original oil in place (OOIP). OOIP was used to determine the initial oil saturation (Soi) in sand pack by volume balance (values are given in Table 2) using Eq.1. S =

* 100

(1)

Thus, the amount of irreducible water saturation (Swi), as given in Table S1 (supporting information), is given by Eq. 2. Swi = 1- Soi

(2)

The effective permeability of oil (ko) at Swi was also measured using Darcy’s law and by measuring the pressure drop of the oil and the oil flow rate at Swi (Table S1, supporting information). Each sand-pack was aged for 10-12 h with crude oil at Swi and test temperature to achieve sand to be 100% saturated with oil. Subsequently, brine was injected at a constant injection rate (20 ml/h, which corresponded to a capillary number of 10-6, which is representative of subsurface flow) to establish the residual oil saturation (Sor) state, and the associated oil recovery under water flooding conditions (until a water cut of 100% was reached). The sand pack at Sor was now targeted for EOR by injecting 0.5 PV of nanofluid (NP and NSP), and the results were compared with analogue results from P and SP floods as conventional EOR alternatives (see Table 1 for fluid compositions). Finally, 3.5 PV of chase brine were injected until oil production from the sand-pack ceased.

3. Results and Discussion In this section, first, the results for the dispersion stability of the nanofluids (NP and NSP) are presented, followed by the discussion of the viscosity of the various fluids (P, SP, NP, and NSP) used. ζ-potentials and particle sizes of the nanoparticles in the nanofluids are provided 12 ACS Paragon Plus Environment

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to understand the stability aspects. IFT results for the crude oil with the various injection fluids are discussed. Furthermore, nanoparticle adsorption on the sand surfaces has been investigated via SEM, and results are presented to understand the nanoparticle retention. Lastly, experimental results on EOR using nanofluids and conventional injection fluids, viz., polymer flood and surfactant-polymer flood (P and SP flood) at two different temperatures are discussed. This includes insights into the possible effects of nanofluids on the wettability of the sand surfaces.

3.1. Characterization of NP and NSP nanofluids Initially, visual observations were made with respect to the stability of the various nanofluids. NP nanofluids of varying SiO2 concentration (0.5 to 2.0 wt%) were left in transparent vessels to analyze their dispersion stability at ambient conditions. Nanoparticle sedimentation was continuously monitored for several days after the preparation. All nanofluids were white in appearance, but showed varying nanoparticle sedimentation behavior; while the 0.5 wt% SiO2 NP nanofluid (which was least dense) started showing sedimentation after around one month time period, the 1.0 wt% SiO2 nanofluid (which was dense) settled after 27 days (Figure 3a). 1.5 and 2.0 wt% SiO2 nanofluids settled after 22 and 19 days, respectively. NSP nanofluids which contained SDS were also tested for stability, however, dispersion stability decreased in the presence of SDS (phase separation occurred after 17 days for the 0.5 wt% SiO2 nanofluid and after 27 days for the 1.0 wt% SiO2 nanofluid; after 15 days for the 1.5 wt% SiO2 nanofluid NSP and 9 days for the 2.0 wt% SiO2 nanofluid). Thus, nanofluids prepared with nanoparticle concentrations >1.0 wt% showed acceptable dispersion stability of approximately 1-3 weeks. Figure 3 also illustrates the phase behavior of NP and NSP nanofluids (1.0 wt% SiO2 concentration) after 1 and 27 days of preparation. It is clear from the Figure that the sedimentation was higher in case of NSP nanofluid. To analyze the effects behind the different 13 ACS Paragon Plus Environment


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sedimentation rates, the size distribution of nanoparticles in NP and NSP nanofluids was measured using DLS method. Clearly, the nanoparticles (15 nm in size originally) agglomerated and formed clusters with sizes between ∼2000-4000 nm, as shown in Figure 4. Specifically, the average size of nanoparticle aggregates in NP nanofluid was found to be around 3.54 µm while it was 4.01 µm in the NSP nanofluid. SDS thus induced additional flocculation of nanoparticles; which is consistent with literature data.44,45 However, the aggregate size decreased with time (27th day: 3.17 µm for NP and 2.12 µm for NSP nanofluid). This indicates that larger size aggregates settled and only smaller aggregates were left in the suspension. Thus, the size of suspended particles in NSP fluid is found to be less after 27 days than that in NP fluid. Note that suspended nanoparticles are solid flocs of higher density than the surrounding fluid and thus settled with time due to gravity. We also performed DLS measurements for NP and NSP nanofluids formulated with 1.5 and 2.0 wt% SiO2. The average nanoparticle aggregate size in NP nanofluid was larger for 1.5 wt% SiO2 (4.12 µm) and 2.0 wt% SiO2 (4.54 µm) than for 1.0 wt% SiO2 (3.54 µm), and their size further increased in the presence of SDS (5.54 µm for 1.5 wt% SiO2) and (6.17 µm for 2.0 wt% SiO2). ζ-potentials of NP and NSP nanofluids have also been measured (see Figure 5). Note that nanoparticle dispersions exhibiting ζ-potentials larger than ± 30 mV are stable, while ζ-potentials between -30 and +30 mV are unstable.46 The ζ-potentials for our nanofluids decreased with time; initially the ζ-potential of the NP nanofluid was -53.1 mV on the 1st day, but it slightly reduced to -51.2 mV (7th day) and -49 mV (27th day). ζ-potentials for the NSP nanofluid were similar, but slightly lower, -47.1 mV (1st day), -45.2 mV (7th day), and -41.3 mV (27th day). Lower ζpotentials indicate the propensity of nanoparticles to aggregate more in the NSP than the NP nanofluid,47 consistent with the particle size measurements and stability behavior (Figure 3 and 4). However, the ζ-potentials remained significantly higher than -30 mV, even after 27 days 14 ACS Paragon Plus Environment

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(Figure 5). To further explore these effects, the ζ-potential of the NSP nanofluid was measured at a random higher SDS concentration (2 wt%). At this increased surfactant concentration (2 wt%), the NSP nanofluid showed enhanced sedimentation and broke down within 4-6 hours. The ζpotential associated with this nanofluid was -11.2 mV, which clearly indicates unstable conditions, see above. Binks and Rodrigues45 also investigated the effect of SDS on the dispersion stability of hydrophilic nanoparticles for emulsification applications. They observed that SDS (of CMC concentration) partially adsorbed on the surfaces of suspended nanoparticles. As a consequence, two different charges on the surfaces of the dispersed nanoparticles developed, which significantly promoted the flocculation of the particles. The flocculation finally resulted in the quick sedimentation of nanoparticles due to the overall increase in particle size and reduced the stability of dispersion. This effect probably also occurred in our investigation. Therefore, lower ζ-potentials and worse dispersion stability results for the NSP nanofluid. Figure 6 shows the effect of temperature on the viscosity of the P, SP solutions and NP and NSP nanofluids. The viscosity of both nanofluids was significantly higher, by a factor of ∼3, than that of P and SP solutions, which is consistent with literature data.48 Higher fluid viscosity is beneficial for oil recovery as this can provide favorable mobility ratios, a better capillary number, and oil recovery factor.29,30 However, NP nanofluid viscosity decreased in the presence of SDS; this is possibly due to the relaxation of PAM molecules in the presence of SDS.49,50 Furthermore, the effect of temperature on the viscosity of NP and NSP nanofluids was relatively less than that on the P and SP fluids (Figure 6). This indicates that the SiO2 nanoparticles have a favorable effect on the rheological properties of the nanofluids, particularly at elevated temperatures; i.e. where conventional EOR chemicals (P and SP) may not be thermally stable, nanofluids (NP and NSP) show potential for high temperature EOR applications. 15 ACS Paragon Plus Environment


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3.2. Influence of nanofluid on the oil-water interfacial tension IFT measurements were conducted for crude oil against various fluids (P, SP, NP and NSP). Figure 7 shows the IFTs measured on the 1st and 27th day of sample preparation (stored at 30 oC). The IFT of the crude oil-P system was higher (18.03 mN/m on 1st day; and 17.02 mN/m on 27th day) than that of the crude oil-SP system (4.9 mN/m on 1st day; 5.13 mN/m on 27th day). Note that the lower IFT in case of crude oil-SP fluid system is caused by surfactant adsorption at the crude oil-water interface.51,52 In case of the nanofluids, the IFT of both the crude oil-NP/NSP systems showed a minimum IFT values at 1.0 wt% SiO2 (see Figure 7); and this minimum was in each case lower than the corresponding P/SP fluids (for NP nanofluid, the minimum IFT was 10.22 mN/m (1st day) and 11 mN/m (27th day) at 1.0 wt% SiO2 concentration). The increase in IFT above 1.0 wt% SiO2 concentrations might be due to the saturation of nanoparticles at the crude oil-nanofluid interface,53 which displace surfactant molecules from the crude oil-water interface. As expected, IFT values of the NSP nanofluids were significantly lower at each solid concentration than the corresponding NP-IFT [IFT of NSP nanofluid (1.0 wt% SiO2 concentration) were 1.12 mN/m (1st day) and 1.65 mN/m (27th day)]. This is caused by a synergistic effect between surfactants and nanoparticles: both adsorb to some extent at the interface and thus reduce IFT. Figure 8 illustrates the effect of temperature on the IFT of the crude oil-P/SP/NP/NSP systems. NSP showed the lowest IFT, and temperature only minimally affected the NSP-IFT. The actual IFT values obtained could be minimum which might not be measured due to the limitation of the equipment and, may need additional investigations to justify nanofluid importance in reducing crude oil IFT value to ultra-low values. However, the study observed reasonable decrease in IFT value of crude oil using nanofluid, which consequently resulted in significant increase in oil recovery from sand-pack flood experiments. These findings based on 16 ACS Paragon Plus Environment

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the use of nanofluid for EOR are in line with the reported EOR results showing favourable effect of nanofluid on crude oil IFT,35,38 associated oil recovery,21,22 and wettability alteration.15,16 This nanofluid characteristic is of great importance when dealing with high temperature oil recovery applications, where conventional EOR chemicals typically show extensive degradation.22

3.3. Enhanced Oil Recovery Experiments 14 flooding experiments have been performed using various fluids/nanofluids at 30 and 90 oC. Tables 2 and S2 (supporting information) summarize the oil recovery results for the various sand-packs. Furthermore, Figure 9 (a-b) show the pressure drops measured vs. pore volume of the injected fluid at 30 and 90 oC. For all tests, the pressure drop during brine flooding remained low and constant at around ∼0.05 to 0.07 MPa. However, the pressure drop increased to 0.248 MPa and 0.142 MPa during P and SP flood at 30 oC, respectively. The lower pressure drop observed for SP flood was caused by the lower viscosity of SP solution, consistent with the viscosity measured for these systems (see Figure 6). Pressure drops for NP and NSP nanofluids were still higher (0.318 MPa (NP nanofluid) and 0.35 MPa (NSP nanofluid)), Figure 9a. The occurrence of high pressure drops in NP and NSP nanofluid flood systems is due to their higher viscosity as compared to P and SP fluids (see Figure 6). The pressure drop then relaxed back to its initial value (0.05-0.07 MPa) at the end of the chase brine flood. Furthermore, at 30 oC, the pressure drop during the chase brine flood did not reach its initial value (0.05-0.07 MPa), but remained at 0.1-0.11 MPa. This indicates that the permeability of the sand-pack decreased after NP/NSP nanofluid injection, due to nanoparticle adsorption/retention in the sand-pack, this is discussed further below. These observations are also consistent with the observations of Ehtesabi et al.33 who observed that TiO2 nanofluid led to pore blockage due to the deposition of nanoparticles in pore channels of the sandstone core. 17 ACS Paragon Plus Environment


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The effect of temperature (90 oC) on the pressure drop was also investigated (see Figure 9b). The pressure drop during the P and SP flood significantly reduced at 90 oC (when compared to 30 oC), while it only reduced marginally for the NP and NSP floods. Precisely, the pressure drops for NP and NSP nanofluids reduced by 10% and 11.2%, respectively, while it reduced by 35.5% and 29.6% for P and SP floods, respectively. This demonstrates that the nanofluids were more stable with respect to maintaining the pressure drop during flooding at varying temperatures, which is an important feature for EOR operations. It is to be noted here that the higher and constant pressure drop is beneficial for successful EOR operations.31 The oil recoveries for different flood schemes at 30 oC are summarized in Table 2 and Figure 9c; the oil recovery after brine flooding remained around 44-48% OOIP; however all chemical floods (P/SP/NP/NSP) have shown enhanced oil recovery. The P and SP floods increased recovery to 58.17% and 62.11% OOIP (the improved recovery in case of the SP flood is due to the lower IFT associated with the SP flood) and the NP and NSP floods increased recovery to 60-63% OOIP, and 65-70% OOIP (the higher recoveries for the NP/NSP flood than the P and SP floods were due to the lower IFT, higher viscosity, and associated higher pressure drops in the sand-pack). The cumulative oil recovery for the nanofluids was better for nanoparticle concentrations ranging from 1.0-1.5 wt%, which is consistent with their lower IFT values (see Figure 7). Figure 9d and Table S2 (supporting information) show the results for the cumulative oil recoveries at 90 oC. With an increase in temperature, oil recoveries for the P and SP floods decreased drastically from 58.17% (at 30 oC) to 52.10% (at 90 oC) and 62.11% (at 30 o

C) to 55.76% (at 90 oC), respectively. However, in case of the nanofluids the recovery was only

marginally affected (reduction from 62.22% (at 30 oC) to 61.67% (at 90 oC) for NP nanofluid (1.0 wt% SiO2); and reduction from 70.45% (at 30 oC) to 68.82% (at 90 oC) for NSP nanofluid (1.0 wt% SiO2) (Figure. 9c and 9d)). These results are consistent with viscosity, IFT, and 18 ACS Paragon Plus Environment

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pressure drop results for P, SP, NP and NSP flood systems, see above. These results indicate that the SiO2 nanofluids in aqueous polymer and polymer-surfactant systems have improved the efficiency of conventional P and SP floods, thus indicating promising use for EOR applications.

3.4. Nanoparticle Retention SEM characterization was performed to understand nanoparticle retention in sand-pack after NP and NSP (1.0 wt% SiO2) floods. Figure 10 (a-b) shows SEM images of NP and NSP nanofluids taken immediately after their preparation. It is clear from the images that nanoparticles flocculated and formed clusters in the aqueous PAM and SDS-PAM phase. This is consistent with studies of Xue and Sethi54 who reported that nanofluid containing water soluble polymer embed nanoparticles in jelly like polymer structures and consequently, larger clusters are formed. We furthermore observed that the nanoparticle flocs formed in NSP nanofluid were larger than those formed in the NP nanofluid system (Figure 10b), consistent with the DLS measurements, see above. Indeed, efforts have to be made to control their size by incorporating nanoparticle surface modifications, etc.45 In order to investigate the nanofluid transport through the sand-pack, SEM characterization was performed on the sand collected from the inlet and outlet portions of the NP flooded sand-pack (Figure 10c, inlet; Figure 10d, outlet). Clearly (Figure. 10c and 10d) the nanoparticles adsorbed at the sand surfaces. However, the deposition was more significant in case of the NSP flood due to the larger size of SiO2-nanoparticle aggregates. The better penetration efficiency of NP was probably caused by the smaller nanoparticle aggregate size. Nanoparticle adsorption was also analyzed gravimetrically by measuring the weight of the dry sand before and after flooding. Pure sand and flooded sand was carefully cleaned using reagent grade toluene followed by heating in an oven at 250 oC for 72-92 h. Thus, the weight of sand 19 ACS Paragon Plus Environment


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after nanofluid flooding was observed to increase by 11.02% in case of the NSP flood and 6.8% in case of the NP flood, which is consistent with the SEM analysis. The investigation on SDS adsorption on sand surface is practically important and will help to estimate the amount of loss of surfactant during EOR projects of surfactant flooding. The mixing of nanoparticle with surfactant may minimize surfactant adsorption on sand resulting effective utilization of surfactant for EOR project. This indicates that EOR fluid prepared using surfactant in the presence of nanoparticle may provide better results for oil recovery and wettability alteration by reducing the surfactant adsorption on the rock surface. As suggested, new surfactant adsorption experiments were carried out on sand using SP fluid without nanoparticles, and the results are compared with the results of NSP nanofluid of SiO2. This may help to understand the effect of nanoparticle on SDS adsorption on sand surface for surfactant based EOR processes. The experimental results were conducted at an ambient pressure and temperature conditions of 1 bar and 313 K. In this study, the amount of surfactant adsorption was determined by the method reported in available literature.55 The amount of surfactant adsorption, S (in mol/g sand), is calculated by the following relationship:55

S=

(

)

(3)

C1 and C2 represent initial and equilibrium concentration of SDS in wt%, respectively. w1 and w2 are the weight of 1000 ppm PAM solution and sand used for adsorption experiment, respectively. M represents molecular weight of SDS (i.e., 288.4 g/mol). The initial concentration of SDS (C1) in SP fluid and NSP nanofluid is 0.14 wt% (i.e., 140 ppm). To determine equilibrium concentration of SDS, viz., C2, 100 ml of SP fluid and 50 g of sand was thoroughly mixed and left in a vessel for more than 24 h to attain equilibrium between sand and surfactant solution.56 Finally, a small amount of solution was taken from the vessel and analysed in UV-vis 20 ACS Paragon Plus Environment

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spectrophotometer (model: 3200, Lab India) to calculate C2. For NSP nanofluid, the method utilized to determine C2 of SDS was similar except nanofluid equilibrated solution with sand was filtered before analysing in UV-vis spectrophotometer. Sand used for adsorption experiments is properly cleaned with distilled water and dried in an oven before mixing with SP fluid and NSP nanofluid. SDS significantly adsorbed on sand during SP fluid experiment and the value of C2 was determined to be around 0.06 wt% (i.e. 60 ppm). The value of S is now calculated as 5.45 x 10-6 mol/g (using Eq. 3). The mixing of SiO2 in SP fluid for NSP nanofluid resulted significant reduction in SDS adsorption on sand and the value of equilibrium SDS concentration, C2, was determined to be around 0.103 wt% (i.e., 103 ppm). SDS adsorption for NSP nanofluid was determined to be around 2.53 x 10-6 mol/g, reduced by ∼54% as compared to the amount associated with SP fluid. 3.5. Wettability alteration by nanofluids Wettability alteration by nanofluids can be very substantial,24 and oil recovery factors can be improved through the modification of brine relative permeability.57 We thus tested SiO2 nanofluids (0.1 wt% SiO2 concentration) in terms of their ability to change relative permeabilities using the procedure proposed by Giraldo et al.57 for alumina nanofluids. Initially, a residual water saturation state was established by injecting crude oil into the (brine saturated) sand-pack, and the effective permeability to oil (Ko) at residual water saturation (Swr) was measured. Subsequently, the sand-pack was flooded with brine and the effective permeability to water (Kw) at residual oil saturation (Sor) was measured (temperature was always below 30 °C). Effective permeabilities were determined at regular intervals using Darcy’s law and the data obtained from the flooding experiments. The same experiment was then repeated with nanofluid (flood sequence: oil, nanofluid (NP and NSP), brine, oil) and relative permeability (Kr = Ki/K; i = oil or brine) curve for brine and oil after nanofluid injection were measured.57 21 ACS Paragon Plus Environment


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Swr before nanofluid injection was found to be 0.282 (NP) and 0.30 (NSP), cp. Figure 11 and Table 3, which indicates intermediate-wet conditions.58 In addition, the cross-over points between oil and brine relative permeabilities occurred at 0.53 (NP nanofluid) and 0.54 (NSP nanofluid), which is greater than 0.5 and thus also indicates intermediate-wet conditions.58 Swr significantly increased after the nanofluid injection (see Table 3 and Figure 11). Furthermore, the relative permeability curves and cross over points shifted to the right; the cross over points occurred at Sw = 0.60 (NP) and at Sw = 0.66 (NSP), which indicates a wettability shift from intermediate-wet to strongly water-wet.58 This is caused by deposition of SiO2 nanoparticles on the sand-pack grains.24 We conclude that SiO2 nanofluids rendered the sand pack significantly more water-wet.

4. Conclusions The use of silica nanofluids as a chemical-EOR agent has shown great potential and can be an alternative to improve the oil recovery from reservoirs where conventional techniques face challenges. In this study, formulation and characterization of nanofluids of SiO2 nanoparticles (∼15 nm) in the base fluid of aqueous PAM polymer (NP nanofluid) and surfactant-polymer (NSP nanofluid) have been reported, including IFT measurements against crude oil and EOR coreflooding experiments. These results were compared with the conventional polymer (P) and surfactant-polymer (SP) flooding techniques. IFT measurements showed that the addition of SiO2 nanoparticles can significantly reduce IFT values of the P and SP systems (if formulated correctly), which is generally beneficial in terms of achieving higher oil recovery. Furthermore, oil recoveries for the P and SP floods decreased with increasing temperature, while the nanofluids showed more stable behavior at higher temperature, and thus may be particularly suitable for high temperature applications. Overall, more than 60% cumulative oil recovery has 22 ACS Paragon Plus Environment

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been achieved for nanofluids of all SiO2 concentrations and test temperatures. SEM images indicated nanoparticle retention in the sand-pack, thereby decreasing the permeability. The nanofluids also shifted wettability from intermediate-wet to strongly water-wet, which was caused by SiO2 nanoparticle adsorption onto the partially oil-wet sand grains, consistent with AlAnssari et al.24 Such nanofluids might thus be useful for CO2 geo-storage applications, where more water-wet conditions are beneficial.59,60 We conclude that SiO2 nanofluids can significantly increase oil recoveries, particularly at higher temperatures.

Acknowledgment Authors thank Department of Ocean Engineering, IIT Madras for providing the experimental facility for the study. Authors also gratefully acknowledge the support from the Department of Chemical Engineering (Polymer Engineering & Colloid Science Group), IIT Madras, Chennai to carry some of the experimental analysis.

Supporting Information Petro-physical properties of sand-packs and preferred reservoir parameters (Table S1), and oil recovery results of flooding tests at 90 oC (Table S2)

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(56) Zargartalebi, M.; Kharrat, R.; Barati, N. Enhancement of surfactant flooding performance by the use of silica nanoparticles. Fuel 2015, 143, 21-27. (57) Giraldo, J.; Benjumea, P.; Lopera, S.; Corte, F. B. Ruiz, M. A. Wettability alteration of sandstone cores by alumina-based nanofluids. Energy Fuels 2013, 27, 3659-3665. (58) Craig, F. F. The Reservoir Engineering Aspects of Waterflooding; SPE Mono-graph Series: TX, 1971. (59) Iglauer, S.; Al-Yaseri, A. Z.; Rezaee, R.; Lebedev, M. CO2-wettability of caprocks: Implications for structural storage capacity and containment security. Geophysical Research Letters 2015, 42, 9279-9284. (60) Iglauer, S.; Pentland, C. H.; Busch, A. CO2 wettability of storage and seal rock and implications for carbon geo-storage. Water Resources Research, 2015, 51, 729-774.

Table 1 Compositional details and nomenclature for fluids used. Fluid Crude oil

PAM solution

Aromatics (A) Resins (R) Asphaltene (A) 76.2% 3.0% 0.4% ° API gravity: 25.57 and viscosity: 22.8 cP Nanoparticle Surfactant Polymer Nomenclaturea (wt%) (wt%) (ppm) P 0.0 ----1000 Saturates (S) 20.4%

SDS-PAM solution SP 0.0 0.14 1000 SiO2-PAM NP 0.5; 1.0; 1.5; 2.0 ----1000 nanofluid SiO2-SDS-PAM NSP 0.5; 1.0; 1.5; 2.0 0.14 1000 nanofluid a P = polymer; SP = surfactant-polymer; NP = nanoparticle-polymer; NSP = nanoparticle-surfactantpolymer


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1 2 3 Table 2 4 5 Summary of oil recovery results for flooding tests conducted at 30 oC. 6 7 Sor additional oil recovery 8 injected nanoparticle (%) (% OOIP) water-flood tertiary oil 9 sandslug concentration slug Soi After After chase 10 recovery recovery after slug after chase (wt%) volume (%) brine brine flood (% OOIP) 11pack no. type (% OOIP) flood brine flood (% 12 (PV) flood (%OOIP) (% OOIP) OOIP) 13 (%OOIP) 14 1 P 0.0 0.5 69.98 55.40 41.83 44.60 5.34 8.23 13.57 15 16 17 2 SP 0.0 0.5 72.12 53.86 37.89 46.14 4.75 11.22 15.97 18 19 3 0.5 71.01 51.88 39.89 48.12 3.88 8.11 11.99 20 21 4 1.0 72.22 52.89 37.78 47.11 4.89 10.22 15.11 22 0.5 NP 23 5 1.5 69.87 54.41 36.88 45.59 5.01 12.52 17.53 24 6 2.0 67.98 51.97 37.71 48.03 3.88 10.38 14.26 25 26 7 0.5 70.98 53.69 34.44 46.31 5.98 13.27 19.25 27 28 8 1.0 66.58 54.23 29.55 45.77 7.23 17.45 24.68 29 NSP 0.5 30 9 1.5 68.77 55.45 31.23 44.55 8.66 15.56 24.22 31 2.0 70.88 53.01 32.11 46.99 6.83 14.07 20.90 32 10 33 34Soi = initial oil in place; Sor = residual oil saturation; Injection strategy: 2.0 PV brine flood + 0.5 PV slug (P, SP, NP, and NSP) flood + 3.5 PV 35 36chase brine flood 37 38 39 40 41 42 43 44 31 45 46 ACS Paragon Plus Environment 47 48

cumulative oil recovery (% OOIP) 58.17 62.11 60.11 62.22 63.12 62.29 65.56 70.45 68.77 67.89


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Table 3 Effect of NP and NSP nanofluids on effective permeabilities of oil and brine. nanofluid type

NP

NSP

Kw (Sw = 1)

1001

984

condition before nanofluid injection after nanofluid injection before nanofluid injection after nanofluid injection

Ko at Swr (mD)

Kw at Sor (mD)

Sor (%)

Swr (%)

cross-over at Sw (%)

846

247

54.44

28.18

53.01

898

212

38.99

34.10

59.69

780

275

54.98

30.10

53.68

857

254

31.25

33.12

66.22


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Figures

Figure 1. XRD analysis of silica sand used in this study.

Figure 2. Schematic of apparatus used for flooding experiments. 33 ACS Paragon Plus Environment


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Figure 3. Images of (a) NP and (b) NSP nanofluids with 1.0 wt% SiO2 concentration at 1st (left) and 27th (right) day after preparation.

Figure 4. Time dependent nanoparticle size distribution measured for (a) 1.0 wt% SiO2 NP and (b) 1.0 wt% SiO2 NSP nanofluids at 30 oC.


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Figure 5. Zeta-potentials measured for 1.0 wt% SiO2 nanofluids in different dispersion media at 30 oC and at different time intervals.

Figure 6. Effect of temperature on the viscosity of various fluids/nanofluid prepared in this work NP nanofluid (1.0 wt% SiO2), NSP nanofluid (1.0 wt% SiO2).



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Figure 7. IFT measured for different crude oil-fluid systems (P, SP, NP, and NSP) over time (on 1st and 27th day) at 30°C. The effect of increasing nanoparticle concentration (0.5, 1.0, 1.5, and 2.0 wt% SiO2) is indicated.


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Figure 8. IFTs measured for different crude oil-fluid systems (P, SP, NP, and NSP) as a function of temperature. The NP and NSP nanofluids had a 1.0 wt% SiO2 concentration



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Figure 9. Pressure drop (images a and b) and cumulative oil recovery (images c and d) as a function of fluid pore volumes injected at 30 and 90 oC. F indicates the interval when P, SP, NP nanofluid (1.0 wt% SiO2), or NSP nanofluid (1.0 wt% SiO2) was injected.


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Figure 10. SEM images of (a) NP and (b) NSP nanofluid (1.0 wt% SiO2) in the presence of aqueous PAM and SDS-PAM at 30 oC, (c) and (d) are SEM images of sand grains, taken from inlet and outlet ends of sand-packs flooded by NP nanofluid.



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Figure 11. Relative permeability curves for brine (empty symbols) and oil (dark symbols) before and after (a) NP and (b) NSP flood as a function of water saturation at 30 oC. 0.1 wt% SiO2 concentrations were used in the nanofluids.


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Silica Nanofluids in an Oilfield Polymer ... - ACS Publications

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