Formation Damage in Oil and Gas Reservoirs: Nanotechnology Applications for Its Inhibition/Remediation (Nanotechnology Science and Technology: ... Technologies, Regulations and Safety) 1536139025, 9781536139020

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NANOTECHNOLOGY SCIENCE AND TECHNOLOGY

FORMATION DAMAGE IN OIL AND GAS RESERVOIRS NANOTECHNOLOGY APPLICATIONS FOR ITS INHIBITION/REMEDIATION

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NANOTECHNOLOGY SCIENCE AND TECHNOLOGY

FORMATION DAMAGE IN OIL AND GAS RESERVOIRS NANOTECHNOLOGY APPLICATIONS FOR ITS INHIBITION/REMEDIATION CAMILO ANDRÉS FRANCO ARIZA AND

FARID BERNARDO CORTÉS CORREA EDITORS

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Library of Congress Cataloging-in-Publication Data Names: Franco Ariza, Camilo Andrés, editor. | Cortés Correa, Farid Bernardo, editor. Title: Formation damage in oil and gas reservoirs: nanotechnology applications for its inhibition/remediation / Camilo Andrés Franco Ariza, Ph.D., and Farid Bernardo Cortés Correa, Ph.D., Research Group in Surface Phenomena, Facultad de Minas Colombia, Sede Medellín, Colombia, editors. Description: Hauppauge, New York: Nova Science Publishers, Inc., [2018] | Series: Nanotechnology science and technology | Series: Environmental remediation technologies, regulations and safety | Includes bibliographical references and index. Identifiers: LCCN 2018030526 (print) | LCCN 2018033121 (ebook) | ISBN 9781536139037 (ebook) | ISBN 9781536139020 (hardcover) | ISBN 9781536139037 (ebook) Subjects: LCSH: Formation damage (Petroleum engineering) | Nanofluids--Industrial applications. Classification: LCC TN871.24 (ebook) | LCC TN871.24 .F676 2018 (print) | DDC 622/.338--dc23 LC record available at https://lccn.loc.gov/2018030526 \

Published by Nova Science Publishers, Inc. † New York

CONTENTS Preface Chapter 1

Chapter 2

vii Multiparameter Methodology for Skin-Factor Characterization Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez Precipitation of Particles in Oil Wells: A Methodology for Estimating the Level of Risk of Formation Damage C. Herrera Perez, M. Ruiz Serna and Richard D. Zabala

Chapter 3

Nanoparticle Fabrication Methods Esther Bailón-García, Agustín F. Pérez-Cadenas, Elizabeth Rodríguez-Acevedo and Francisco Carrasco-Marín

Chapter 4

Wettability Alteration in Sandstone Cores Using Nanofluids Based on Silica Gel Stefanía Betancur, Camilo A. Franco and Farid B. Cortés

1

27

71

153

vi Chapter 5

Chapter 6

Chapter 7

Chapter 8

Contents Synergy of SiO2 Nanoparticle-Polymer in Enhanced Oil Recovery Process to Avoid Formation Damage Caused by Retention in Porous Media and Improve Resistance to Degradative Effects Lady J. Giraldo, Sebastian Llanos, Camilo A. Franco and Farid B. Cortes Inhibition of the Formation Damage due to Fines Migration on Low-Permeability Reservoirs of Sandstone Using Silica-Based Nanofluids: From Laboratory to a Successful Field Trial D. Arias-Madrid, N. Ospina, C. Céspedes, E. A. Taborda, Elizabeth Rodríguez-Acevedo, H. Acuña, O. Botero, J. E. Patiño, Camilo A. Franco, Richard D. Zabala, S. H. Lopera and Farid B. Cortés Application of Nanofluids for Improving Oil Mobility in Heavy Oil and Extra-Heavy Oil: A Field Test Richard D. Zabala, Camilo A. Franco and Farid B. Cortés Application of Nanofluids in Field for Inhibition of Asphaltene Formation Damage Richard D. Zabala, H. Acuña, J. E. Patiño, Farid B. Cortés, Camilo A. Franco, S. H. Lopera, C. Céspedes, E. Mora, O. Botero and L. Guarín

185

231

285

307

About the Editors

325

Index

327

PREFACE For years, formation damage was considered negligible or was not treated adequately, causing reductions in the production rate up to the loss of both producer and injector wells. Nowadays, formation damage is an essential parameter to be considered in the wells development as its prevention and/or engineered remediation may lead to costs reduction and productivity improvement. Formation damage is challenging in the oil and gas industry as it implies a large number of mechanisms that can reduce the productivity of an oil or gas producing formation, as well as inhibit the injectivity in injection wells. Different fields feature problems associated with fines migration, asphaltene precipitation/deposition, inorganic scales, condensate banking, and damage during hydraulic fracturing operations, among others. Recently, nanotechnology has emerged as an attractive alternative in the oil and gas industry for the inhibition and remediation of different types of formation damage. Nanotechnology offers exceptional characteristics that allow nanoparticles to travel smoothly through porous media without additional risks of formation blockage due to their small size. At the nanoscale, exceptional properties can be obtained, such as a high surface-areato-volume ratio, high thermal stability, chemical stability, and dispersibility, as well as optically, magnetically, and electrically tunable properties.

viii Camilo Andrés Franco Ariza and Farid Bernardo Cortés Correa This book provides recent research on nanotechnology applied to the inhibition/remediation of formation damage in oil and gas reservoir. The book includes methodologies for multi-component skin characterization, estimating the level of risk of formation damage, nanoparticle fabrication methods, as well as the application of nanoparticles and nanofluids at both laboratory and field conditions. Chapter 1 - In this chapter, a skin-factor characterization methodology that has been developed and successfully applied in various fields in Colombia, South America, is presented. This method uses basic statistical correlations to rank different measured or estimated damage parameters. The primary purpose of this method is to generate estimated multicomponent skin characterization maps by weighting the different formation damage mechanisms operating in the complex reservoirs of the Colombian foothills. The presence of compositional fluids, active tectonic environments, stacked reservoirs, and well access issues account for the complexity of this environment. The application of the proposed methodology enhances the design efficiency of chemical stimulations as its output, multiparameter skin characterization, can be applied to all wells. The stimulation packages include components for the control of the main skin mechanisms via the estimated model ratios. The model is continuously updated through the incorporation of measured and estimated damage-related variables, including physical–chemical analyses of backflowed samples (after stimulations), output from mineral and organic scaling index estimation models, laboratory studies, and well-intervention records, all of which are routinely taken into account for the entire life of a particular well. This multiparameter model applies a newly developed skin characterization mapping tool that has been recognized an essential input in the periodical reviews of well productivity. Stimulation and wellintervention options are efficiently ranked with respect to their benefits, which also leads to better planning of well work campaigns. The proper diagnosis and control of formation damage are crucial for realizing production sustainability in mature fields affected by any particular skin. The simultaneous presence of several damage mechanisms

Preface

ix

often adds complexity to diagnostic exercises, and critical challenges arise when multipurpose control packages are deployed for a particular well. The context of the discussion in this chapter are fields located in the Colombian foothills where the damage mechanism is multifaceted [1]. The model serves as a tool for leveraging the prediction of formation damage in a well in complex environments associated with multilayer reservoirs, fluid behaviors driven by a compositional gradient, and some degree of damage associated with any of the three production phases (oil, water, and gas), the rock, or external factors. Chapter 2 - This chapter presents a methodology and models to predict the risk level of formation damage due to deposition of asphaltene, wax, and fines in producer wells. This deposition can cause serious production problems due to reduced permeability, altered wettability, and/or clogging of pores in the vicinity of the wellbore. Thus, research on the precipitation nature and properties of particles in crude oil is currently particularly important. Asphaltenes, fines, and waxes were separated and studied in the laboratory, and the dominant mechanism of precipitation was determined using the obtained data. The maximum deposited amount varies according to fluid conditions and the properties of the medium. During the transport of reservoir fluids from formation to the surface, the most common causes of particle deposition are changes in velocity or density or alteration of the composition of the fluids. Chapter 3 - In this chapter, it is presented the methodologies used in the synthesis of nanoparticles, which can be either bottom-up or top-down. The first method builds particles by the use of atoms or molecules and the second starts with large material nanoparticles produced by different processes. In this text, it is also discussed the historical materials and methods used in the synthesis of carbon-based nanomaterials, review their properties, and describe the different types of carbon nanomaterials. Also, the procedures employed concerning metallic, bimetallic, and ceramic nanomaterials are presented, including the colloidal method, photochemistry, and radiochemistry reduction, microwave radiation, and sol-gel method.

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Camilo Andrés Franco Ariza and Farid Bernardo Cortés Correa

Chapter 4 - The aim of this investigation is to evaluate the effectiveness of silica-based nanofluid in altering the sandstones core wettability with an induced oil-wet wettability and compare its performance with that of a commercial surfactant. For this study, silica nanoparticles were synthesized by using the sol-gel method. Nanofluids with different concentrations between 100 mg/L and 10,000 mg/L were prepared by dispersing silica nanoparticles in an aqueous solution. Similarly, fluids with commercial surfactants were prepared with concentrations between 100 mg/L and 10,000 mg/L by dispersion in an aqueous solution. The effect of the nanofluids and the commercial surfactants on altering the wettability was evaluated by the contact angle and the imbibition test. The results illustrated the nanofluid provided better performance in altering the wettability of the rock over that of the commercial surfactant. The best performance was achieved when a concentration of 100 mg/L was used. It was shown that the nanofluids could change the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Additionally, a core-displacement test was performed by injecting a nanofluid into the sand pack by dispersing silica nanoparticles in an aqueous solution. A reduction in the residual oil saturation, an increment of oil mobility, and a displacement to the right of the oil relative-permeability curve were obtained, which indicated that the nanofluid restored the rock wettability. Chapter 5 - As an enhanced oil recovery technique, the polymer injection process has been widely used in recent years to improve sweeping efficiency in the hydrocarbon extraction process. However, the application of this technique has severe limitations, one of which is its adverse generation of formation damage processes in the reservoir by pore throat plugging or retention on porous media. Also, the various degradation processes to which the polymer is subjected due to reservoir conditions also leads to severe formation damage and operational problems. The primary objective of this work is to develop a suitable nanofluid for strengthening this enhanced recovery technique by reducing the possible adverse effects associated with formation damage and by generating a synergistic effect favoring the polymer’s integrity, based on the interaction

Preface

xi

of SiO2 nanoparticles with hydrolyzed polyacrylamide (HPAM). This nanofluid was evaluated under different scenarios, in adsorptive processes, aggregate sizes, and adsorption and retention in porous media, as well as its rheological behavior concerning temperature (thermal stability). Also characterized the sample of the nanoparticles and HPAM using thermogravimetric analysis (TGA), Fourier-transform infrared spectroscopy (FTIR), and dynamic light scattering (DLS). It is conducted a batch-type adsorption process to maintain a fixed polymer concentration while varying the dosage of nanoparticles. The adsorption results show that the obtained isotherms exhibited Type-III behavior. Also, it is used UVVis spectrophotometry to measure the adsorption in porous media via batch mode. Then the adsorption isotherms were correlated with a solidliquid equilibrium (SLE) model, obtaining a good fit with an RSME of less than 10%. Similarly, the rheological behavior was fitting to the HerschelBulkley model with an RSME of less than 1%. The rheological tests were performed at 25ºC and 70ºC and found non-Newtonian behavior in all the SiO2–HPAM mixtures tested. The thermal stability of polymeric solutions was evaluated in the absence and presence of nanoparticles under oxidative atmospheres at 70°C for 14 days. The results show significant decreases in aggregate sizes by the addition of nanoparticles to the system, which decreases the probability of plugging the pores. Also was observed a lower degree of degradation in the presence of nanoparticles, which can be explained by the adsorptive function of HPAM onto SiO2. Chapter 6 - The main objective of this chapter is to inhibit the fines migration based on the laboratory studies and conduct a field test for a reservoir of condensated gas and low permeability. This work was performed through a systemic study divided into two steps: 1) Evaluation of the nanoparticles based on silica at room and reservoir conditions in porous media with low permeability, to obtain the optimal concentration of nanofluid for field test, and 2) A trial test on a field of condensated gas and low-permeability sandstones based on the previous results obtained with the reservoir conditions. In this way, two commercial nanoparticles based on silica were characterized by the Brunauer-Emmet-Teller method to determine the surface area (SBET), fill emission scanning electron

xii

Camilo Andrés Franco Ariza and Farid Bernardo Cortés Correa

microscopy (FE-SEM), and dynamic light scattering (DLS). Posteriorly, the nanofluids were prepared using salt water (2%wt of KCl in deionized water) and the two commercial nanoparticles at desired different concentrations (0–20,000 mg/L). The effect of the nanofluids on inhibition of the fines migration was initially evaluated on sandstone beds under normal room conditions. Two types of packed beds were assembled using Ottawa sand: 1) oil-wet and 2) water-wet, which were soaked with specifical nanofluids at different concentrations using a fines suspension based on an average chemical composition from the a field, located in Colombia. The treatments showed a higher capacity of stabilizing the fines for the oil/water-wet beds. The best performance of the nanofluid was achieved when a concentration of 500 mg/L was used. Additionally, a core displacement test (sand-pack) was conducted using injection of a nanofluid at different flow rates. The treatment was very effective in altering the critical rate flow, which was assessed before and after the treatment based on the nanofluid. The results showed an increase of 400% in the critical velocity relative to the untreated nanofluid. The field test was successful, which showed increases of oil production of 100 bbls per day during the first month of evaluation and a reduction of the production of water around 40% regarding post-pickling. Chapter 7 - Nanofluids, or “smart fluids,” can be designed by tuning nanoparticle properties and are prepared by adding small concentrations of nanoparticles to the liquid phase to enhance or improve some of the fluid properties. However, the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present a field evaluation of nanofluids for improving oil mobility and mitigate wettability alterations in two Colombian heavy oil fields: CA and CH. Asphaltene sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil-based nanofluid (OBN) containing these nanoparticles was evaluated as a viscosity reducer under static conditions. Displacement tests through a porous media in core plugs under reservoir conditions were also performed at CA and CH. The OBN was evaluated for its ability to reduce oil viscosity under various oil temperature and water content conditions. The

Preface

xiii

maximum change in oil viscosity was achieved at 122 °F with 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests (caused by the removal of asphaltenes from the aggregation system), reduced oil viscosity, and effectively restored the original core wettability. Two field trials were performed in CA (CN1 and CN2 wells), by forcing 200 bbl and 150 bbl of nanofluid, respectively, as the main treatment within a ~3 ft penetration radius. Instantaneous oil rate increases of 270 bopd in CN1 and 280 bopd in CN2, and BSW reductions of ~11% were observed. In CH, two trials were also performed (CH1 and CH2) by forcing 86 bbl and 107 bbl of nanofluid, respectively, as main treatment within a ~3 ft penetration radius. Instantaneous oil rate increases of 310 bopd in CH1 and 87 bopd in CH2 were achieved; however, BSW reduction has yet to be observed. The interventions were performed a few months ago, and the long-term effects are still under evaluation. Nevertheless, the results look promising and encourage the extension of this nanofluid application to other wells in these fields. Chapter 8 - This chapter describes the use of nanomaterials for asphaltenes inhibition under reservoir conditions. In CP Sur field, some traditional methods have been evaluated for asphaltenes inhibition. Asphaltenes precipitation in the near wellbore has been confirmed as one of the major components of formation damage in CP field. The asphaltenes inhibition test involves the injection of nanofluids containing nanoparticles to adsorb the asphaltenes before being flocculated and transported in the product fluids, thereby avoiding precipitation near the wellbore and downhole. The first part of this chapter describes the adsorption kinetics and the adsorption capacity of various nanomaterials for samples of asphaltenes. The sorption kinetics of asphaltenes on locally produced nanoalumina and other nanomaterials was determined in an asphaltenes concentration range of 250–1500 mg/L. From the results of the laboratory evaluation, it was determined that the locally produced nano-alumina exhibited excellent properties for asphaltenes sorption and may be incorporated into a nanofluid free of aromatic solvents, which are the traditional major components used in the formulations of asphaltenes inhibitors and dispersants.

xiv Camilo Andrés Franco Ariza and Farid Bernardo Cortés Correa The nanofluid was evaluated in core flow testing under reservoir conditions, and it was observed that the synthesized nanofluid improved the permeability to oil. Then, a pilot test in CP1well was used as a field trial by injecting 220 bbl of nanofluid containing alumina nanoparticles into the geologic formation. After seven months of job tracking, asphaltenes remained stable in produced oil, and the oil production was above the baseline level.

In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 1

MULTIPARAMETER METHODOLOGY FOR SKIN-FACTOR CHARACTERIZATION Alejandro Restrepo1, *, Jorge Enrique Duarte2 and Yamile Sánchez3 1

Well Productivity - E&P Technology, Equión Energía, Bogotá, Colombia 2 Ecopetrol S.A., Bogotá, Colombia 3 Nalco, Bogotá, Colombia

ABSTRACT In this chapter, we present a skin-factor characterization methodology that has been developed and successfully applied in various fields in Colombia, South America. This method uses basic statistical correlations to rank different measured or estimated damage parameters. The primary purpose of this method is to generate estimated multicomponent skin characterization maps by weighting the different formation damage mechanisms operating in the complex reservoirs of the *

Corresponding Author Email: [email protected].

2

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez Colombian foothills. The presence of compositional fluids, active tectonic environments, stacked reservoirs, and well access issues account for the complexity of this environment. The application of the proposed methodology enhances the design efficiency of chemical stimulations as its output, multiparameter skin characterization, can be applied to all wells. The stimulation packages include components for the control of the main skin mechanisms via the estimated model ratios. The model is continuously updated through the incorporation of measured and estimated damage-related variables, including physical–chemical analyses of backflowed samples (after stimulations), output from mineral and organic scaling index estimation models, laboratory studies, and well-intervention records, all of which are routinely taken into account for the entire life of a particular well. This multiparameter model applies a newly developed skin characterization mapping tool that has been recognized an essential input in the periodical reviews of well productivity. Stimulation and wellintervention options are efficiently ranked with respect to their benefits, which also leads to better planning of well work campaigns. The proper diagnosis and control of formation damage are crucial for realizing production sustainability in mature fields affected by any particular skin. The simultaneous presence of several damage mechanisms often adds complexity to diagnostic exercises, and critical challenges arise when multipurpose control packages are deployed for a particular well. The context of the discussion in this chapter are fields located in the Colombian foothills where the damage mechanism is multifaceted [1]. The model serves as a tool for leveraging the prediction of formation damage in a well in complex environments associated with multilayer reservoirs, fluid behaviors driven by a compositional gradient, and some degree of damage associated with any of the three production phases (oil, water, and gas), the rock, or external factors.

Keywords: formation damage, disaggregation, skin factor, multiparameter methodology

NOMENCLATURE 𝐴 𝐴𝑠 𝐶𝐼𝐼 𝐼𝐷𝑃

= Fraction of aromatics (undimensional) = Fraction of asphaltenes (undimensional) = Colloidal inestability index (undimensional) = Induced damage parameter (undimensional)

Multiparameter Methodology for Skin-Factor Characterization 𝐼𝐹𝑇 𝐹𝐵𝑃 𝐾𝑟𝑃 𝑀𝑆𝑃 𝑂𝑆𝑃 𝑅 𝑅𝑂𝑃 𝑅𝐼 𝑆 𝑆. 𝐼. 𝑉𝑐

3

= Interfacial tension (dyne/cm) = Fines blockage parameter (undimensional) = Relative permeability parameter (undimensional) = Mineral scaling parameter (undimensional) = Organic scaling parameter (undimensional) = Fraction of resins (undimensional) = Rate of penetration while drilling (ft/h) = Refractive index (undimensional) = Fraction of saturates (undimensional) = Mineral scale index (undimensional). Scaling tendency exists if 𝑆. 𝐼. > 1.0. = Critical velocity (ft/h)

1. SCOPE OF MODEL In this section are described the mechanics of the multiparameter model for skin-factor characterization, which was developed and applied in Colombia for the prognosis of formation damage in wells. First, a brief description of the types of input data is presented. Second, the methodology used in deriving the model parameters is detailed, and finally, the model outputs are showed. Two types of data sets provide the basis for the skin characterization multiparameter model: i) Theoretical data related to the outputs of various formation damage models that provide estimations of mineral scale indexes, asphaltene stability indexes, critical velocity radii, dynamic filtration rates under drilling mud exposure, and the interfacial tensions in reservoir conditions in which external fluids invade the formation; and ii) measured data related to measured properties such as reservoir and saturation pressures, production rates, physical–chemical analyses of backflowed samples (after chemical stimulations) and produced fluids, volumes of injected external fluids and polymers, and petrophysical properties. The application of this model enables the incorporation of skin parameters related to five different damage mechanisms for each evaluated well. These damage mechanisms are

4

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

chosen based on historical experience and applied this model to wells that typically exhibit high skin-damage factors, 𝑆.

2. DESCRIPTION OF THE MULTIPARAMETER METHODOLOGY This methodology derives a skin characterization for each well based on five mechanisms: mineral scaling, organic scaling, fines blockage, induced damage, and relative permeability effects. The parameters associated with each mechanism for a well 𝑗 are defined as the mineral scaling parameter (𝑀𝑆𝑃), organic scaling parameter (𝑂𝑆𝑃), fines blockage parameter (𝐹𝐵𝑃), induced damage parameter (𝐼𝐷𝑃), and relative permeability parameter (𝐾𝑟𝑃).

2.1. Mineral Scaling Parameter (𝑴𝑺𝑷) The 𝑀𝑆𝑃 is calculated as an average value of five subparameters related to CaCO3 (𝑀𝑆𝑃1), BaSO4 (𝑀𝑆𝑃2), iron scales (𝑀𝑆𝑃3), the calcium concentration on backflowed samples (𝑀𝑆𝑃4), and the barium concentration on backflowed samples (𝑀𝑆𝑃5). Table 1 summarizes the equations used to calculate these mineral scaling subparameters, which are evaluated as a function of the scale index (𝑆. 𝐼.). Figure 1 shows the data set used in the calculation of the subparameters associated with scaling tendency for a) CaCO3, b) BaSO4, c) iron related scales, d) the Ca concentration measured on backflowed samples, and e) the Ba concentration measured on backflowed samples. It can be arbitrarily defined and relate subregions to the different levels of influence of these subparameters in a well. For example, in the scaling tendency of CaCO3 in Figure 1(a), it can be observed a low influence if the maximum 𝑆. 𝐼. calculated for the well is P10 and P50 and P90. The P10, P50, and P90 values are the 10%, 50%, and 90% percentiles, respectively, of the total cumulative distribution of the CaCO3 𝑆. 𝐼. calculated values (for all the wells).

a)

b)

c)

d)

e) Figure 1. a) Histogram of CaCO3 scaling Index calculated for all the wells. P90 = 6.2; P50 = 1.8, P10 = 0.6, Parameter = 15. b) Histogram of BaSO 4 Scaling Index calculated for all wells. P90 = 5.3, P50 = 1.7, P10 = 0.7, Parameter = 12. c) Histogram of iron related scales Scaling Index calculated for all wells. P90 = 4.0, P50 = 0.10, P10 = 0.05, Parameter = 2.0. d) Histogram of calcium concentration measured on back flow samples. P90 = 2200 ppm, P50 = 1100 ppm, P10 = 500 ppm, Parameter = 4400 ppm. e) Cumulative frequency of barium concentration measured on back flow samples. P90 = 26 ppm, P50 = 8.0 ppm, P10 = 5.2 ppm, Parameter = 46 ppm.

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Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

In general, the parameter associated with mineral scales for a particular well can be represented as shown in Figure 2. The total 𝑀𝑆𝑃 can be calculated as an arithmetic or geometric average of the 𝑀𝑆𝑃1 to 𝑀𝑆𝑃5 subparameters or according to the user’s criteria by defining weight factors for each one. Table 1. Equations for the estimation of mineral scaling subparameters

Equation number

Parameter

𝑀𝑆𝑃1 =

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝑎𝐶𝑂3 𝑆. 𝐼. 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑆. 𝐼. 𝐶𝑎𝐶𝑂3 𝑓𝑟𝑜𝑚 𝑎𝑙𝑙 𝑑𝑎𝑡𝑎 𝑎𝑣𝑎𝑖𝑙𝑎𝑏𝑙𝑒

(1)

𝑀𝑆𝑃2 =

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐵𝑎𝑆𝑂4 𝑆. 𝐼. 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑆. 𝐼. 𝐵𝑎𝑆𝑂4 𝑓𝑟𝑜𝑚 𝑎𝑙𝑙 𝑑𝑎𝑡𝑎 𝑎𝑣𝑎𝑖𝑙𝑎𝑏𝑙𝑒

(2)

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐼𝑟𝑜𝑛 𝑆𝑐𝑎𝑙𝑒𝑠 𝑆. 𝐼. 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑆. 𝐼. 𝐼𝑟𝑜𝑛 𝑆𝑐𝑎𝑙𝑒𝑠 𝑓𝑟𝑜𝑚 𝑎𝑙𝑙 𝑑𝑎𝑡𝑎 𝑎𝑣𝑎𝑖𝑙𝑎𝑏𝑙𝑒

(3)

𝑀𝑆𝑃3 =

Maximum Ca concentration measured on backflow data available for well j 𝑀𝑆𝑃4 = Maximum Ca concentration measured on all backflow data available.

(4)

Maximum Ba concentration measured on backflow data available for well j 𝑀𝑆𝑃5 = Maximum Ba concentration measured on all backflow data available.

(5)

Multiparameter Methodology for Skin-Factor Characterization

7

Figure 2. Type diagram of mineral scale parameter for a particular well.

2.2. Organic Scaling Parameter (𝑶𝑺𝑷) We calculate the 𝑂𝑆𝑃 as a function of four subparameters: the colloidal instability index (𝑂𝑆𝑃1), chemical alterations factor (𝑂𝑆𝑃2), compositional factor (𝑂𝑆𝑃3), and reservoir pressure factor (𝑂𝑆𝑃4). We can calculate the 𝑂𝑆𝑃1 as follows: 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝐼𝐼 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑖𝑛 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗

𝑂𝑆𝑃1 = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝐼𝐼 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑖𝑛 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠,

(6)

where 𝐶𝐼𝐼 is the colloidal instability index, which is defined as a function of all the fractions derived from the saturates, aromatics, resins, and asphaltenes (SARA) analysis: 𝐶𝐼𝐼 =

𝑆+𝐴𝑠 . 𝑅+𝐴

(7)

Nevertheless, when lacking sufficient historical (or current) SARA analysis data, correlations can be determined for the 𝐶𝐼𝐼 calculation using

8

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

the Bocanegra and Clavija [2] method as a function of API gravity data as a tool for estimating the tendency of asphaltenes deposition. Hence, the empirical correlation established by Buckley et al. [3] that relates the refractive index (𝑅𝐼) and SARA fractions is as shown in Eq. (8) below: 𝑅𝐼 =

(1.4452∙𝑆+1.4982∙𝐴+1.6624∙(𝑅+𝐴𝑠)) . 100

(8)

Moreover, Fan et al. [4] established an empirical correlation relating 𝑅𝐼 and API values as follows: 𝑅𝐼 = 1.798 ∙ 𝐴𝑃𝐼 −0.0544.

(9)

Table 2. 𝑹𝑰 values calculated using Buckley et al. [3] and Fan et al. [4] correlations RI calculated using Equation 8 1.464 1.461 1.460 1.455 1.465 1.459 1.455 1.458 1.459

RI calculated using Equation 9 1.465 1.465 1.465 1.465 1.469 1.469 1.468 1.467 1.464 Average difference

Difference (%) 0.1 0.3 0.3 0.7 0.3 0.7 0.9 0.6 0.3 0.5%

We calculate the 𝑅𝐼 values for each equation by using the SARA data available from crude oil samples and their corresponding API values. Table 2 lists the 𝑅𝐼 values calculated for different dead crude oil samples taken from the same field. In general, there is a slight difference in these calculated values, which implies that both correlations can be used within a suitable confidence level.

Multiparameter Methodology for Skin-Factor Characterization

9

Hence, based on all the SARA analysis data available for a particular field, a cross-plot of 𝐶𝐼𝐼 vs. 𝑅𝐼 is obtained and a correlation observed, as shown in Figure 3 and Equation 10, respectively.

Figure 3. 𝐶𝐼𝐼 vs. 𝑅𝐼 cross-plot for a particular well.

𝐶𝐼𝐼 = 7 × 1012 𝑅𝐼 −73.784 .

(10)

Finally, Eq. (9) is substituted into Eq. (10) to obtain a direct correlation between 𝐶𝐼𝐼 and API for a particular field: 𝐶𝐼𝐼 = 1.13068 × 10−6 ∙ 𝐴𝑃𝐼 4.012218 .

(11)

We repeat this exercise to obtain a correlation for each field. With the ongoing introduction of new SARA data, continuous adjustments are made. This methodology has become a valuable tool for historical production data analysis with respect to the evaluation of the asphaltenes deposition tendency in wells. Above, it is determined the obtained correlation for field A. For field B, the obtained correlation equation is as follows: 𝐶𝐼𝐼 = 1.8 × 10−4 ∙ 𝐴𝑃𝐼 2.63.

(12)

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Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

Figure 4 shows the data set used to calculate the subparameter associated with 𝐶𝐼𝐼. In general, the critical values for 𝐶𝐼𝐼 depend on the type of fluids present. Values above 2.5 are considered to be critical in the zones of fields in which volatile oil exists, and a value of 3.5 is assumed as a critical value in retrograde gas condensate zones.

Figure 4. Cumulative frequency of 𝐶𝐼𝐼 derived from SARA analysis and API correlation for all wells. P90 = 6.5, P50 = 4.0, P10 = 2.0, Parameter = 10.

Table 3 shows the equations for calculating 𝑂𝑆𝑃2, 𝑂𝑆𝑃3, and 𝑂𝑆𝑃4. The chemical alterations factor (𝑂𝑆𝑃2) weights the asphaltenes destabilization due to the low pH promoted by HCl invasion. Among the evaluated wells, 70% have not experienced HCl invasion; thus, this factor will affect only 30% of the wells. The 𝑂𝑆𝑃3 is related to low-molecularweight gas components such as propane and methane that are rich in saturates, which leads to increases in 𝐶𝐼𝐼. In general, saturate compounds compete against asphaltenes for solubility. Onset laboratory tests have shown that asphaltene precipitation occurs near saturation pressure [1]. Figure 5 shows a histogram of pumped HCl, the cumulative gas produced, and the days below saturation pressure for all wells. In general, the parameter associated with organic scales for a particular well can be presented as shown in Figure 6. The total 𝑂𝑆𝑃 can be calculated as an arithmetic or geometric average of the 𝑂𝑆𝑃1 to 𝑂𝑆𝑃4 subparameters or according to the user’s criteria by defining weight factors for each subparameter.

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11

Figure 5. a) Histogram of HCl pumped on wells. P10 and P50 = 0. P90 = 300 bbl, Parameter = 550 bbl. b) Histogram of cumulative gas produced by all wells. P90 = 176K MMSCF, P50 = 54K MMSCF, P10 = 8K MMSCF, Parameter = 260K MMSCF. c) Histogram of days below saturation pressure for all the wells. P90 = 3300 d, P50 = 2800 d, P10 = 2300 d, Parameter = 4400 d.

12

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez Table 3. Equations for estimating the 𝑶𝑺𝑷𝟐, 𝑶𝑺𝑷𝟑, and 𝑶𝑺𝑷𝟒 subparameters of organic scaling

Parameter

Equation number

𝑂𝑆𝑃2 =

𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑣𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝐻𝐶𝑙 𝑝𝑢𝑚𝑝𝑒𝑑 𝑜𝑛 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝐻𝐶𝑙 𝑣𝑜𝑙𝑢𝑚𝑒 𝑝𝑢𝑚𝑝𝑒𝑑

(13)

𝑂𝑆𝑃3 =

𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑔𝑎𝑠 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 𝑏𝑦 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑔𝑎𝑠 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑

(14)

𝑁𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑑𝑎𝑦𝑠 𝑏𝑒𝑙𝑜𝑤 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑓𝑜𝑟 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑛𝑢𝑚𝑏𝑒𝑟 𝑜𝑓 𝑑𝑎𝑦𝑠 𝑟𝑒𝑔𝑖𝑠𝑡𝑒𝑟𝑒𝑑 𝑏𝑒𝑙𝑜𝑤 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒

(15)

𝑂𝑆𝑃4 =

Figure 6. Type diagram of organic scale parameter for a particular well.

2.3. Fines Blockage Parameter (FBP) The 𝐹𝐵𝑃 is calculated as a function of five subparameters: the aluminum concentration on produced water (𝐹𝐵𝑃1), the silicon concentration on produced water (𝐹𝐵𝑃2), a critical radius factor (𝐹𝐵𝑃3), a mineralogical factor (𝐹𝐵𝑃4), and a crushed proppant factor (𝐹𝐵𝑃5). Figures 7(a) and 7(b) show the data sets of the produced water aluminum and silicon concentrations, respectively. The estimation of the 𝐹𝐵𝑃1 and

Multiparameter Methodology for Skin-Factor Characterization

13

𝐹𝐵𝑃2 subparameters can be made using Eqns. (16) and (17). that by measuring the relative abundance of aluminosilicates, scanning electron microscopy/energy-dispersive X-ray spectroscopy analysis of the solids retained on 0.45-micron membranes can also be considered when determining the 𝐹𝐵𝑃1 and 𝐹𝐵𝑃2 parameters.

𝐹𝐵𝑃1 =

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑎𝑙𝑢𝑚𝑖𝑛𝑢𝑚 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑖𝑜𝑛 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑜𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 𝑤𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑗 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑎𝑙𝑢𝑚𝑖𝑛𝑢𝑚 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑖𝑜𝑛 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 , 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

(16)

𝐹𝐵𝑃2 =

𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑠𝑖𝑙𝑖𝑐𝑜𝑛 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑖𝑜𝑛 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑜𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 𝑤𝑎𝑡𝑒𝑟 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑗 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑠𝑖𝑙𝑖𝑐𝑜𝑛 𝑐𝑜𝑛𝑐𝑒𝑛𝑡𝑟𝑎𝑡𝑖𝑜𝑛 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 . 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

(17)

Figure 7. a) Histogram of aluminum concentration measured on produced water samples. P90 = 0.62 ppm, P50 = 0.3 ppm, P10 = 0.05 ppm, Parameter = 2.0 ppm. b) Histogram of silicon concentration measured on produced water samples. P90 = 38.5 ppm, P50 = 20 ppm, P10 = 6 ppm, Parameter = 50 ppm.

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Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

Figure 8. Illustration of the critical radius concept.

Figure 9. Histogram of critical radii for all wells.

Figure 10. Typical mineralogical characterization values.

Multiparameter Methodology for Skin-Factor Characterization

15

a)

b) Figure 11. a) Typical crushing values for proppants placed on hydraulically fractured wells. b) Histogram of lbs of fines present on hydraulically fractured wells. P90 = 14000 lb, P50 = 0 lb, P10 = 0 lb, Parameter = 27000 lb.

Through core flooding tests, the critical velocity is determined, i.e., the velocity above which fines migration occurs, with and without acid attack to be 16.79 and 8.5 ft/h, respectively, with Ko reductions ranging between

16

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

50% and 80%. The velocity profile can be calcualted assuming a radial flow, for the maximum equivalent liquid rate ever experienced by the well, the percentage of production according to the production logging tool, and the stable flow conditions. The critical radius is defined as the radius at which flow velocity overcomes critical velocity (see Figure 8). In general, the higher is the value of the critical radius, the bigger is the area affected by fines migration. 𝐹𝐵𝑃3 is estimated using Eqn. (18) and the consolidated data of critical radii calculated for all the wells in Figure 9. The critical radii is corrected according to acid interventions (Figure 5a) by assuming the critical velocity measured in lab conditions under acid attack.

𝐹𝐵𝑃3 =

𝐶𝑟𝑖𝑡𝑖𝑐𝑎𝑙 𝑟𝑎𝑑𝑖𝑢𝑠 𝑜𝑓 𝑤𝑒𝑙𝑙 𝑗 𝑑𝑒𝑟𝑖𝑣𝑒𝑑 𝑓𝑟𝑜𝑚 𝑐𝑟𝑖𝑡𝑖𝑐𝑎𝑙 𝑣𝑒𝑙𝑜𝑐𝑖𝑡𝑦 𝑙𝑎𝑏 𝑡𝑒𝑠𝑡𝑠 𝑎𝑡 𝑡ℎ𝑒 𝑚𝑎𝑥𝑖𝑚𝑢𝑚 𝑓𝑙𝑢𝑖𝑑 𝑒𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑝𝑟𝑜𝑑𝑢𝑐𝑖𝑛𝑔 𝑟𝑎𝑡𝑒 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑐𝑟𝑖𝑡𝑖𝑐𝑎𝑙 𝑟𝑎𝑑𝑖𝑢𝑠 𝑏𝑒𝑡𝑤𝑒𝑒𝑛 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

(18)

We define the mineralogical factor (𝐹𝐵𝑃4) based on the maximum recorded kaolinite, illite, and chlorite percentages, with a single value being defined for each formation. Figure 10 shows typical mineralogical characterization values. Generally, the formation with the highest clay content is defined as the parameter. We estimate the 𝐹𝐵𝑃5 as follows: 𝐹𝐵𝑃5 =

𝑇𝑜𝑡𝑎𝑙 𝑙𝑏𝑠 𝑜𝑓 𝑓𝑖𝑛𝑒𝑠 𝑖𝑛 ℎ𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑒𝑠 𝑖𝑛 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 . 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑙𝑏𝑠 𝑜𝑓 𝑓𝑖𝑛𝑒𝑠 𝑟𝑒𝑝𝑜𝑟𝑡𝑒𝑑 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

(19)

We calculate the total lbs of fines according to Figure 11(a) as a function of the volume and type of proppant present and the closure gradient. Figure 11(b) shows a histogram of the total lbs of fines present in all the hydraulically fractured wells. It can be noted that for this particular case, 68% of the wells evaluated have not been fracked. Hence, this factor will affect only 32% of the wells. In general, the parameter associated with fines blockage for a particular well can be presented as illustrated in Figure 12.

Multiparameter Methodology for Skin-Factor Characterization

17

Figure 12. Type diagram of organic scale parameter for a particular well.

2.4. Induced Damage Parameter (𝑰𝑫𝑷) We estimate the 𝐼𝐷𝑃 as an arithmetic or geometric average value of three subparameters: a mud damage factor (𝐼𝐷𝑃1), a polymer damage factor (𝐼𝐷𝑃2), and an invasion fluids factor (𝐼𝐷𝑃3), which is calculated using Eqs. (20), (21), and (22), respectively. 𝐸𝑥𝑝𝑜𝑠𝑢𝑟𝑒 𝑡𝑖𝑚𝑒 𝑡𝑜 𝑑𝑟𝑖𝑙𝑙𝑖𝑛𝑔 𝑚𝑢𝑑 𝑓𝑜𝑟 𝑤𝑒𝑙𝑙 𝑗

𝐼𝐷𝑃1 = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑟𝑒𝑐𝑜𝑟𝑑𝑒𝑑 𝑡𝑖𝑚𝑒 𝑜𝑓 𝑒𝑥𝑝𝑜𝑠𝑢𝑟𝑒 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠, 𝐼𝐷𝑃2 =

(20)

𝑇𝑜𝑡𝑎𝑙 𝑙𝑏𝑠 𝑜𝑓 𝑝𝑜𝑙𝑦𝑚𝑒𝑟 𝑝𝑢𝑚𝑝𝑒𝑑 𝑑𝑢𝑟𝑖𝑛𝑔 ℎ𝑦𝑑𝑟𝑎𝑢𝑙𝑖𝑐 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑒𝑠 𝑖𝑛 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 , 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑙𝑏𝑠 𝑜𝑓 𝑝𝑜𝑙𝑦𝑚𝑒𝑟 𝑝𝑢𝑚𝑝𝑒𝑑 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

(21) 𝐼𝐷𝑃3 =

𝐾𝑖𝑙𝑙𝑖𝑛𝑔 + 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑖𝑛𝑔 𝑓𝑙𝑢𝑖𝑑 𝑝𝑢𝑚𝑝𝑒𝑑 𝑡𝑜 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 .(22) 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝑘𝑖𝑙𝑙𝑖𝑛𝑔 + 𝑓𝑟𝑎𝑐𝑡𝑢𝑟𝑖𝑛𝑔 𝑓𝑙𝑢𝑖𝑑 𝑝𝑢𝑚𝑝𝑒𝑑 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

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Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

a)

b)

c) Figure 13. a) Gross pay values for all wells (assumed as the mud damage parameter). P90 = 720 ft, P50 = 340 ft, P10 = 110 ft, Parameter = 1200 ft. b) Histogram of polymer losses for all wells. c) Histogram of fracturing and killing fluids pumped into all the wells. P90 = 3700 bbl, P50 = 1700 bbl, P10 = 100 bbl, Parameter = 5600 bbl.

Multiparameter Methodology for Skin-Factor Characterization

19

Figure 14. Type diagram of induced damage parameter for a particular well.

We approximate our estimation of the 𝐼𝐷𝑃1 based on gross pay, assuming the same rate of penetration for all the wells and the same dynamic filtration losses. Figures 13(a)–13(c) show a) the values of gross pay for all wells, b) the data set summarizing the lbs of polymer pumped on hydraulic fractures, and c) a histogram summarizing the total fracturing + killing fluid losses. Normalizing by a petrophysical factor defined as (𝑘 ∙ 𝑝𝐻𝐼)2 enables us to weight the level of influence of the 𝐼𝐷𝑃 in tighter formations. It can also be included the interfacial tension of the invading fluids. We represent the parameter associated with induced damage for a particular well as illustrated in Figure 14.

2.5. Relative Permeability Parameter (𝑲𝒓𝑷) We can calculate the total 𝐾𝑟𝑃 as an arithmetic or geometric average of three subparameters related to reservoir pressure (𝐾𝑟𝑃1), the delta pressure from the saturation pressure (𝐾𝑟𝑃2), and a water intrusion factor (𝐾𝑟𝑃3). The subparameter 𝐾𝑟𝑃1 can be calculated as for 𝑂𝑆𝑃4. The assumption behind 𝐾𝑟𝑃1 is that the longer is the time spent below

20

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

saturation pressure, the higher are the cumulative effects on 𝐾𝑔 and 𝐾𝑜 due to the appearance of condensate or the liberation of gas, respectively. Figure 15(a) shows a histogram of the recorded differences between the reservoir and saturation pressures for all the wells, and Figure 15(b) shows the cumulative water production for all the wells.

a)

b) Figure 15. a) Histogram of pressure differences between reservoir and saturation pressures for all the wells. P90 = 1600 psi, P50 = 950 psi, P10 = 520 psi, Parameter = 1880 psi. b) Histogram of cumulative water production recorded in all the wells in January 2007. P90 = 3 MM bbl, P50 = 0.5 MM bbl, P10 = 0.2 MM bbl, Parameter = 20 MM bbl.

Multiparameter Methodology for Skin-Factor Characterization

21

𝐾𝑟𝑃2𝐷𝑒𝑙𝑡𝑎 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑓𝑟𝑜𝑚 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 = 𝑚𝑎𝑥𝑖𝑚𝑢𝑚 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑐𝑒 𝑓𝑟𝑜𝑚 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑓𝑜𝑟 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙 𝑗 . 𝑚𝑎𝑥𝑖𝑚𝑢𝑚 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑖𝑓𝑓𝑒𝑟𝑒𝑛𝑐𝑒 𝑓𝑟𝑜𝑚 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑖𝑜𝑛 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑟𝑒𝑐𝑜𝑟𝑑𝑒𝑑 𝑎𝑚𝑜𝑛𝑔 𝑎𝑙𝑙 𝑡ℎ𝑒 𝑤𝑒𝑙𝑙𝑠

The assumption behind 𝐾𝑟𝑃2 is that the greater the difference between the reservoir and saturation pressures, the higher is the condensate drop out or gas fraction affecting 𝐾𝑔 and 𝐾𝑜. 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑤𝑎𝑡𝑒𝑟 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑 𝑏𝑦 𝑤𝑒𝑙𝑙 𝑗

𝐾𝑟𝑃3𝑊𝑎𝑡𝑒𝑟 𝐼𝑛𝑡𝑟𝑢𝑠𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟 = 𝑀𝑎𝑥𝑖𝑚𝑢𝑚 𝐶𝑢𝑚𝑢𝑙𝑎𝑡𝑖𝑣𝑒 𝑤𝑎𝑡𝑒𝑟 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑. 𝐾𝑟𝑃3 is related to the reduction in 𝐾𝑜 and 𝐾𝑔 due to incremental water saturation. Normalizing by a petrophysical factor defined as (𝑘 ∙ 𝑝𝐻𝐼)2 enables us to weight the level of influence of the 𝐾𝑟𝑃 in tighter formations. Normalizing by a dissolved gas/oil ratio factor will enable a reduction in the net effect of the relative permeability parameter due to the velocity effects on the 𝐾𝑟 values. The parameter associated with relative permeability effects for a particular well is illustrated in Figure 16.

Figure 16. Type of diagram of relative permeability parameter for a particular well.

22

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

2.6. Alternative Calculation for the Normalized Values of the Damage Subparameters The normalized values of the damage subparameters can be calculated in another way that, when the measured value approaches the P90 value of the distribution, the normalized value approaches 1.0. In the aforementioned case, if the value is close to the P10 of the distribution, the normalized value will approach 0. In general, when the value is more than 2 times above the P90 it is assumed that the value is equal to 2 times the P90; if the value is lower than P10, the value of the P10 is assigned to the variable, thus suppressing negative values of the subparameter. The normalized damage paramenter can be calculated as follows: 𝑁𝑜𝑟𝑚𝑎𝑙𝑖𝑧𝑒𝑑 𝑑𝑎𝑚𝑎𝑔𝑒 𝑝𝑎𝑟𝑎𝑚𝑒𝑡𝑒𝑟 =

𝑀𝑒𝑎𝑠𝑢𝑟𝑒𝑑 𝑣𝑎𝑙𝑢𝑒 − 𝑃10 𝑃90 − 𝑃10

Other supplements to the methodology include weighted averages for the calculation of damage parameters (giving differential weight factors to each subparameter) and the inclusion of the parameter of geomechanical damage. With this, it is avoided that the maximum value (as written in the original) is the parameter since sometimes this can be an “outlier” and lead to underestimate of some parameters of damage.

3. SOME MODEL OUTPUTS Apart from obtaining the valuable information detailed in the above histograms, the output has been also applied from the multiparameter model in our tendency analyses and when comparing the levels of influence of different skin mechanisms between wells or fields. This method has become a powerful tool for stimulating the design process. Figures 17 to 21 show a few examples of the model’s output for January 2007. It can be seen that input data must be continuously updated for the parameters to be sufficiently representative.

Multiparameter Methodology for Skin-Factor Characterization

Figure 17. Multiparameter skin characterization diagram for a particular well.

Figure 18. Average multiparameter skin characterization diagrams for two fields.

Figure 19. Ranking of wells according to a particular skin parameter (𝑂𝑆𝑃).

23

24

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

Figure 20. General level of influence of a particular skin mechanism according to the model’s output. Sample: 51 wells.

Figure 21. Area mapping of a particular skin parameter according to the model’s output.

Multiparameter Methodology for Skin-Factor Characterization

25

CONCLUSION •

•

•

•

•

•

We developed a multiparameter methodology for characterizing skin factor through the application of simple statistical concepts associated with the formation damage theory. This methodology is qualitative and provides no information about the value of the mechanical skin on a particular well. However, it estimates the relative level of influence of five different mechanisms on the overall skin value, 𝑆. Skin parameter values reflect the influence levels at any given moment of five damage mechanisms: mineral scales, organic scales, fines blockage, induced damage, and fluid blockage. Continuously updating of the input data is essential for the model to retain its representativeness. Based on our collected data, normal and bi-modal distributions were found to be the most common. Bi-modal behaviors are related to the presence of multiple reservoirs, different types of reservoir fluids, or different operative schemes between fields. Further tuning can be incorporated into the model by assigning weighting factors to different subparameters or by softening the estimated values by considering skin removal events for a particular well. This multiparameter methodology is a powerful tool for diagnosing skin damage in complex environments in which several mechanisms co-exist and for which records are available regarding basic production chemistry, well history, and reservoir data.

ACKNOWLEDGMENTS The authors would like to thank Instituto Colombiano del Petróleo and Universidad de America for their experimental and academic support and BP Exploration Colombia for the permission to publish this chapter.

26

Alejandro Restrepo, Jorge Enrique Duarte and Yamile Sánchez

REFERENCES [1]

[2] [3]

[4]

Franco, C.A., A. Restrepo, L.G. Acosta and E. Junca, SDLA: Fighting Skin Damage in Colombian Fields – A War Story, in SPE International Symposium and Exhibition on Formation Damage Control. 2006, Society of Petroleum Engineers: Lafayette, Louisiana, USA. Bocanegra, G.a.J.C., Study of Asphaltene Precipitation on SOLA Fields. 2005, Universidad de América. Buckley, J.S., G. J. Hirasaki, Y. Liu, S. Von Drasek, J. Wang and B.S. Gill, Asphaltene Precipitation and Solvent Properties of Crude Oils. Petroleum Science and Technology, 1998. 16(3-4): p. 251-285. Fan, T., J. Wang and Jill S. Buckley, Evaluating Crude Oils by SARA Analysis, in SPE/DOE Improved Oil Recovery Symposium. 2002, Society of Petroleum Engineers: Tulsa, Oklahoma.

In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 2

PRECIPITATION OF PARTICLES IN OIL WELLS: A METHODOLOGY FOR ESTIMATING THE LEVEL OF RISK OF FORMATION DAMAGE C. Herrera Perez,* M. Ruiz Serna and Richard D. Zabala2 Universidad Nacional de Colombia–Sede Medellín, Columbia 2 Gerencia de Desarrollo de Yacimientos, Vicepresidencia Técnica de Desarrollo, Bogotá, Colombia

ABSTRACT This chapter presents a methodology and models to predict the risk level of formation damage due to deposition of asphaltene, wax, and fines in producing wells. This deposition can cause serious production problems due to reduced permeability, altered wettability, and/or *

Corresponding Author Email: [email protected].

28

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala clogging of pores in the vicinity of the wellbore. Thus, research on the precipitation nature and properties of particles in crude oil is currently particularly important. Asphaltenes, fines, and waxes were separated and studied in the laboratory, and the dominant mechanism of precipitation was determined using the obtained data. The maximum deposited amount varies according to fluid conditions and the properties of the medium. During the transport of reservoir fluids from formation to the surface, the most common causes of particle deposition are changes in velocity or density or alteration of the composition of the fluids.

Keywords: deposition, asphaltene, paraffin, fines, formation damage, permeability

1. INTRODUCTION Formation damage due to particle deposition is one of the most common problems in the oil industry. The presence of asphaltenes, paraffin, and/or fines can result in serious flow assurance problems, decreased productivity, and increased maintenance costs. Reduced porosity, permeability changes, and wettability changes are the most common types of formation damage [1-3]; viscosity changes, increased molecular weight, and plugging of production lines are frequent surface problems [3-5]. Assessing the magnitude of problems due to organic and inorganic particle deposition is not a simple task. Initially, the reservoir engineer must identify the location of the deposits in the formation and near the wellbore, in downhole and surface equipment, and in separators, lines, and storage tanks. Next, the characteristics of the fluids and the physical properties of the formation must be evaluated, along with its relationship with the stability of the precipitated particles. The intent of this chapter is to demonstrate a methodology for the diagnosis of formation damage caused by deposits of asphaltene, paraffin, and fines particles. Asphaltene deposits result from the association of several asphaltene molecules (precipitation and aggregation), paraffin deposits are formed by growth of heavy hydrocarbon crystals (nucleation),

Precipitation of Particles in Oil Wells

29

and fines deposits are caused by the transport, migration, and swelling of particles in the porous medium. This methodology includes stability analysis using tools with practical use in the field and algorithms for calculating the amounts of asphaltene, wax, and fines deposited in the rock. The diagnostics methodology involves three steps: First, the physical properties of the fluid, such as temperature, pressure, composition, density, concentration of asphaltenes, and paraffin precipitation, are evaluated. Second, the fines migration is analyzed using mathematical and phenomenological models. Third, the concentrations of deposited asphaltenes, paraffin, and fines are calculated near the wellbore to diagnose formation damage.

2. ASPHALTENE DEPOSITS 2.1. General Concepts Oil consists of a mixture of multiple organic compounds containing some non-organic compounds, such as sulfur, nitrogen, and oxygen, and small amounts of trace metals, such as iron, zinc, and nickel. The mixture of organic compounds is known as hydrocarbons; this term refers to compounds containing only carbon and hydrogen atoms. The number of compounds present in petroleum is unknown; thus, they are classified in four (4) well-defined groups: saturated (including paraffins), aromatics, resins, and asphaltenes (SARA). These compounds are classified according to their degrees of solubility and polarity. In SARA analysis, the saturated fraction contains nonpolar materials, while the aromatic fraction contains compounds with polar structures. Asphaltenes and resins are compounds with high molecular weights and polar components; one difference between them is that asphaltenes are insoluble in n-pentane and n-heptane [6].

30

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala (a)

Molecular Formula: C86H99NOS2 Formula Weight: 1226.84236 lb./lbmol Composition: C (84.19%), H (8.13%), N (1.14%), O (1.3%) S (5.23%)

(c)

Molecular Formula: C154H187N3O2S2 Formula Weight: 1226.84236 lb./lbmol Composition: C (84.19%), H (8.13%), N (1.14%), O (1.3%) S (5.23%)

(e)

Molecular Formula: C43H56O Formula Weight: 588.90414 lb./lbmol Composition: C (87.70%), H (9.58%), O (2.72%)

(b)

Molecular Formula: C64H81N Formula Weight: 864.3.3464 Composition: C (88, 93%), H (9, 45%), N (1.62%)

(d)

Molecular Formula: C57H58S2 Formula Weight: 807.20042 lb./lbmol Composition: C (84.81%), H (7.24%), S (7.94%)

(f)

Molecular Formula: C59H63 NOS Formula Weight: 834.20262 lb./lbmol Composition: C (83.66%), H (7.48%), N (1.65%), O (2.98%) S (4.22%)

Figure 1. Molecular structures of asphaltene. (a) Structure proposed by Langevin [20], (b) structure proposed by Greenfield [20], (c) structure proposed by Murgich [21], (d) structure proposed by Zajac [22], (e) structure proposed by Greenfield [20], (f) asphaltene structure of Colombian crude oil.

Precipitation of Particles in Oil Wells

31

The IP 173 standard states: “The asphaltene content of petroleum is the percentage by free weight of paraffins insoluble in n-heptane but soluble in hot benzene.” Asphaltenes are molecular complexes with high molecular weights that occupy large volumes and possess high viscosities [7]. Asphaltenes are also defined as associations of polynuclear aromatic aggregates. The aggregates may be particles, colloids, or macromolecules [8-10]; their stacking consists of four to seven aggregates. The molecular weight of asphaltene is a complex variable to describe due to the organic and non-organic structures it contains. The most common techniques for recording the molecular weight of asphaltene include ionic mass spectroscopy (~700 g/mol), osmometric vapor pressure (~4,000 g/mol), and molecular chromatography (~10,000 g/mol) [11-14]. Recent molecular research techniques have shown that the molecular weight of asphaltenes has a direct relationship with the number of aromatic rings present in the structure of the asphaltenes (between 4 and 10 rings) [15]. The asphaltene molecule is described as an aromatic nucleus system containing oxygen (~1.5 wt%), nitrogen (~1.1 wt%), and sulfur (~7 wt%) heteroatoms on polycyclic structures, as shown in Figure 1. The elemental composition of asphaltenes shows an aromatic carbon ratio approaching 50% [16]. Two types of structures are reported in the literature: archipelago-like and island-shaped. The island-shaped architecture is common in crude oil and is used to explain the formation of asphaltene aggregates in petroleum. Nuclear magnetic resonance techniques, Raman spectroscopy, molecular imaging, and TRFD can be used to help identify these structures [17, 18]. Due to the nature of asphaltenes, it is challenging to understand their general interactions with other components of crude oil; this has led to the development of a variety of approaches to model the behavior of asphaltenes in the formation of aggregates and their subsequent precipitation. Precipitation models are divided into two types: solubility models and aggregation models. Solubility models study the interaction between asphaltenes and other components of crude oil using stability analysis based on solubility parameters. Solubility parameters indicate

32

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

whether the intermolecular forces are directional (hydrogen bonding, electrostatic) or non-directional (van der Waals and other polar forces) and their effects on solubility. The origin of asphaltenes is mainly linked to the formation of petroleum bitumen. The organic material undergoes different geological processes (diagenesis, catagenesis, metagenesis) over millions of years, during which organic structures, such as kerogen, break into lighter fractions. Tissot and Welte [19] stated that hydrocarbons that are subjected to high pressure and temperature conditions show structures with lower molecular weights (gaseous hydrocarbons and light liquids), while hydrocarbons that undergo early diagenesis have long and heavy chains with high aromaticity indices (asphaltene). Figure 2 shows the process that hydrocarbon undergoes and describes the different types of crude oil that may contain asphaltenes. In general, crude oils containing less than 10% paraffin and less than 20% naphthenic content with an intermediate aromatic range of 10%–40% may contain asphaltenes.

2.2. Precipitation of Asphaltene In their primary production processes, asphaltenes promote the formation of solid compounds, which can cause pore plugging in the reservoir matrix. The maximum precipitated amount of asphaltenes varies according to the fluid conditions and medium. In theory, precipitation curves for pure asphaltenes yield a higher value of precipitated asphaltenes compared to the precipitated amount of resin-asphaltene mixture because unstable asphaltenes form aggregates and occupy fewer active sites on the surface of the rock at the time of deposition, as shown in Figure 3. The maximum amount of precipitated asphaltenes depends on the concentration of associable asphaltenes and the concentration of resins and aromatics in the medium. Asphaltene aggregates result from the association of various asphaltene monomers. The number of monomers varies between 2 and 10,

Precipitation of Particles in Oil Wells

33

and the concentration range is 3 g/L [9]. Interaction forces such as van der Waals forces, dispersion, induction, electrostatics, hydrogen bonds, and aromatic stacking facilitate the formation of aggregates. The obtained structures have high molecular weights; they tend to separate from the liquid phase and precipitate due to the effects of Brownian forces and gravity.

Figure 2. General formation scheme of hydrocarbons [19].

Figure 3. Formation of asphaltene precipitate from a mixture of asphaltenes and resins.

34

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

As shown in Figure 4, particles formed by the association of asphaltene molecules are in equilibrium with disassociated asphaltenes; the resins act as a natural dispersant and may be associated with asphaltene particles but not with other resins, and the resins associated with asphaltenes form a dynamic equilibrium with non-associated resins. Similar to resins, aromatics act as solvents in the asphaltenic matrix, while saturates act as non-solvents and stimulate the aggregation and precipitation of asphaltenese. In the system shown in Figure 4, the asphaltenes are suspended in a delicate balance that can be disturbed by an increase in saturates or a decrease in the amounts of resins and/or aromatics. The formation of aggregates is considered to be a reversible process that depends on pressure changes [3, 23]; however, the effects of temperature are not entirely clear. At low temperatures, the aggregation kinetics of asphaltenes is slow. Some authors prefer to consider the aggregation process as partially reversible [24], especially under conditions below the onset of precipitation. One of the most common reversibility considerations occurs at the laboratory scale, where asphaltenes dissolve completely in organic solvents. The other approach is based on the fact that asphaltene aggregates are colloids suspended in crude oil and are stabilized

Figure 4. Physical model of oil.

Precipitation of Particles in Oil Wells

35

by adsorption of resins. The adsorption process occurs either mechanically or by electrostatic attraction. These perspectives of reversibility involve the creation of thermodynamic models that can be used to understand the behavior of asphaltenes in their natural environment and to evaluate the effects of precipitation in liquid-solid and/or liquid-liquid systems. An oil sample is considered to be unstable if precipitated asphaltenes are observed. Precipitation is the phenomenon of formation of semi-solid compounds from the liquid phase upon changes in pressure, temperature, and composition. Stability criteria are practical tools to detect asphaltene precipitation problems in the reservoir and support relevant theories, such as aggregation, resin stabilization, and saturation of light hydrocarbons.

2.2.1. The Solubility Parameter The concept of the solubility parameter [25, 26] is described as the change in cohesive energy in the following equation: 𝜹𝟐 =

∆𝑼 𝒗

(1)

where 𝛿 is the solubility parameter, 𝑈 is the internal energy of vaporization, and 𝑣 is the molar volume. Another method of calculating the solubility parameter [13, 27-29] uses the vaporization enthalpy, as follows: 𝜹𝟐 =

∆𝑯𝒗𝒂𝒑 −𝑹𝑻 𝒗𝒍𝒊𝒒

(2)

These thermodynamic models are tools for predicting the behavior of asphaltenes. In the literature, the cubic state equations are highlighted; these allow modeling of the liquid-vapor (ELV) and liquid-asphaltene (ELA) equilibrium as a function of the solubility parameter, molar volume, pressure, and temperature [1, 7, 11, 15, 30-34]. The cubic equations predict the behavior of the internal energy as a function of the interaction parameters of the molecules. For the PengRobinson equation, the solubility parameter is calculated as follows:

36

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala 𝜹𝟐𝑳 =

√𝟐 (𝒂 − 𝟒𝒃𝒗

𝑻

𝒗 + 𝒃(√𝟐 + 𝟏) 𝒅𝒂 ) [𝐥𝐧 ( )] 𝒅𝑻 𝒗−𝒃(√𝟐−𝟏)

(3)

where 𝑎 and 𝑏 correspond to the attractive and co-volume terms, respectively. Table 1. Solubility parameters of asphaltenes Asphaltene solubility parameter [𝑀𝑃𝑎0.5 ] 19.5 17.6–21.3 19–21 19–22 20–20.5 20–23 20–24

Researchers (Year) Hirschberg et al. (1984) Lian (1994) Yarranton and Masliyah (1996) Anderson (1999) Wang and Buckley (2001) Verdier (2006) Panter and Veytsman (2015)

Estimating the solubility parameter of asphaltenes is difficult, and the obtained mathematical results show a high degree of uncertainty. Many authors have proposed that the calculation should be performed employing temperature and molecular weight corrections. Limitations would be restricted to aggregate sizes, internal energy, and asphaltene density.

2.2.2. Stability of Asphaltene The stability criterion can function as a prediction tool [35] that enables evaluation of the damage index at the reservoir according to the pressure conditions. The maximum precipitated amount of asphaltenes varies according to the fluid conditions and medium. In theory, precipitation curves for pure asphaltenes yield a value of precipitated asphaltenes from a mixture of hydrocarbons. Variables affecting the stability of asphaltenes and statistical models to predict stability are described below. The effect of pressure is more pronounced near the bubble point. Asphaltenes stabilize at high pressures to the point of pressure onset, where the concentration of asphaltenes becomes zero. As the pressure decreases

Precipitation of Particles in Oil Wells

37

during the oil production process, the relative volume of the fraction of light components increases, the solubility of the asphaltene in the oil decreases, and the flocculation process begins. When the temperature of the crude oil decreases, the solubility of the oil decreases so that the asphaltene particles destabilize and aggregate, forming higher molecular weight aggregates and resulting in a change in precipitation. Although the process does not follow a defined stabilization pattern, the asphaltenes tend to flocculate at low temperatures and finally are deposited in the walls of the pipe by a nucleation effect. The most common cause of deposition at low temperatures is the presence of paraffins; when not evaporated, they cause a considerable decrease in the stability of the asphaltenes, which form larger particles that are eventually deposited. In general, asphaltenes become more stable in heavy crude oils than in light crude oils because the viscosity and resin content of the former help to stabilize the asphaltene content; thus, precipitation is not expected. Problems due to high crude oil saturation occur more frequently in light crude oil [36]. CO2, N2, and CH4 are often used to improve crude oil solvency and increase production, minimizing gravitational and fluid channeling effects. However, fluid injection for improved recovery or injection of damage remediation treatment decreases the solubility of asphaltenes, thus increasing the percentage of precipitates. Three types of crude oil are shown in Table 2. The first contains high saturated high molecular weight components, while the second and third are rich in low molecular weight saturates. Crude oil 1 is described as a heavy crude oil with low API gravity; although the asphaltene content is very high, the solvency of the asphaltenes is very low, and it is expected that no precipitation of asphaltenes will occur in the reservoir. While crude oil 2 is enriched with light hydrocarbons, the contents of methane gas, carbon dioxide, and nitrogen are relatively low and enable the precipitation of asphaltenes. Crude oil 3 is a light crude oil with high concentrations of CH4 and CO2, and the solvency conditions are high. Although the

38

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

asphaltene concentration is low, the deposition rate is considerably higher than those of crude oils 1 and 2. Table 2. Concentrations of asphaltenes in SARA analysis of three samples of Colombian crude oil Properties/Well name N2 CO2 C1 C2 C3 IC4 nC4 iC5 NC5 C6 C7 + Saturates (%Wt) Aromatics (%Wt) Resin (%Wt) Asphaltene (%Wt) API Density Provided by ECOPETROL. S.A.

Oil 1 0.084 0.130 1.228 0.653 1.042 0.550 1.225 1.037 1.080 2.157 90.810 18.239 23.044 43.446 15.271 13.400 0.9822

Oil 2 2.520 0.290 38.270 7.320 5.070 1.340 2.360 1.300 1.320 2.160 38.030 52.200 33.400 7.000 7.400 29.800 0.965

Oil 3 0.148 4.101 49.855 9.032 6.568 2.009 3.539 1.554 1.236 1.322 20.630 71.240 19.440 9.130 0.200 38.060 0.590

When the fluid naturally contains high concentrations of CO2, N2, and CH4, the producer well is expected to contain asphaltene deposits from the start of production. When the composition of the formation fluid is changed with the injection gas, the properties of the fluid are expected to cause precipitation of asphaltenes during the residence time of the injection fluid. Boer, in 1995, explained that asphaltenes require some degree of supersaturation before the precipitate appears; otherwise, many production operations would be very difficult to perform because the surface facilities would become clogged in a short time. Precipitation depends on many factors, such as weather, temperature, turbulence, and the medium in which

Precipitation of Particles in Oil Wells

39

precipitation occurs. The relative changes in solubility due to decreasing pressure enable increases in the amount of asphaltene precipitate [36]. Changes in temperature have a slight effect on the solubility of asphaltenes. The Boer’s plot shown in Figure 5 displays the severity of the problems according to the difference between the reservoir pressure and the saturation pressure. The diagram is pessimistic and assumes that the entire site is saturated with asphaltenes. The colloidal stability index described by Yen in 2001 [12] predicts stability using resin/asphaltene ratios. It is calculated from the SARA fractions of petroleum using the following relation: 𝐶𝐼𝐼 =

% 𝑠𝑎𝑡𝑢𝑟𝑎𝑡𝑒 + % 𝑎𝑠𝑝ℎ𝑎𝑙𝑡𝑒𝑛𝑒 % 𝑟𝑒𝑠𝑖𝑛𝑠 + % 𝑎𝑟𝑜𝑚𝑎𝑡𝑖𝑐𝑠

(4)

By combining stability analysis and laboratory tests, it is possible to combine precipitation possibilities and to obtain the risk level of crude oil. Table 3 shows a risk analysis for Colombian crude oil.

Figure 5. Maximum supersaturation of asphaltenes at bubble pressure.

40

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala Table 3. Risk of asphaltene precipitation determined by SARA analysis

2.2.3. Mathematical Model of Precipitation of Asphaltene Currently, published studies describing precipitation, deposition, and clogging around wells combine two models: a thermodynamic model describing the precipitation of asphaltenes from crude oil due to pressure changes near the face of the well and a fluid flow model that also explains the deposition and clogging [37]. Asphaltenes in solution are considered to be a two-component system: a pure phase of asphaltenes and a second phase that is rich in oil, including resins. The asphaltenes phase that is separated from the liquid phase is calculated with the Flory-Huggins model, which considers asphaltenes as monodisperse polymer molecules. Hirschberg et al. obtained the following expression to determine the soluble fraction of asphaltenes [26, 38-41]: 𝑣

𝜙𝐴 = 𝑒𝑥𝑝 ( 𝑣𝐴 [1 − 𝐿

𝑣𝐿 𝑣𝐴

𝑣

− 𝑅𝑇𝐿 (𝛿𝐴 − 𝛿𝐿 )2 ])

(5)

where 𝜙𝐴 is the volumetric fraction of asphaltenes in the oil, 𝑣𝐴 and 𝑣𝐿 are the molar volumes of asphaltenes and oil, respectively, and 𝛿𝐴 and 𝛿𝐿 are the solubility parameters of the asphaltenes and oil, respectively.

41

Precipitation of Particles in Oil Wells

Figure 6. Precipitation of asphaltene at constant temperature.

Chung et al. [1] modified this theory by assuming that changes due to pressure were insignificant. The prediction model is executed on the basis of the principle of liquid-solid equilibrium as a function of temperature, composition, and the activity coefficients of soluble asphaltenes in an organic solution. The Chung model intends to correct the Hischberg model from experimental approximations, which is synthesized in the following expression: 𝑋𝐴𝐿 = 𝑋𝐴𝑆 exp [−

∆𝐻𝐴 1 (𝑇 𝑅

−

1 ) 𝑇𝐴𝑀

𝑉 ̅̅̅𝐿 − 𝛿𝐴 )2 − 𝑙𝑛 𝑉𝐴 − 1 + − 𝑅𝑇𝐴 (𝛿 ̅̅̅̅ 𝑉 𝐿

𝑉𝐴 ̅̅̅̅ 𝑉𝐿

] (6)

where 𝑋𝐴𝐿 is the mole fraction of asphaltenes dissolved in the oil. ∆𝐻𝐴 , 𝑇𝐴𝑀 , 𝑅, 𝛿𝐴 , and 𝑉𝐴 are the latent heat of vaporization, vaporization temperature, ideal gas constant, solubility parameter, and molar volume of the solid asphaltenes, respectively, and ̅̅̅ 𝛿𝐿 and ̅̅̅ 𝑉𝐿 are the solubility parameter and the molar volume of the liquid phase, respectively. The asphaltene precipitation envelope is constructed based on the onset pressure of the system. The onset pressure corresponds to the pressure where the asphaltenes begin to destabilize and subsequently precipitate. It also corresponds to the pressure at which the amount of soluble asphaltenes is zero, as shown in Figure 6. The envelope is constructed to

42

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

determine the areas of asphaltene instability as a function of pressure and temperature, the areas where the liquid and asphaltenes are in equilibrium above the bubble pressure, the liquid-vapor balance, and the areas where the liquid and asphaltenes are in equilibrium below the bubble pressure. An example of an envelope is shown in Figure 7.

3. PARAFFIN DEPOSITS 3.1. General Concepts Paraffins are also known as alkanes or saturates; they differ from other compounds due to the presence of chains composed of single C-C bonds. Alkanes are hydrocarbons that contain only single bonds. The general formula is: 𝐶𝑛 𝐻2𝑛 + 2

(7)

At environmental conditions, paraffins with one to four carbons are gaseous. Paraffins with saturated chains of 4 to 16 carbons are liquids. Paraffins formed of chains with 18 to 60 carbons are solids and have high molecular weights (both straight-chain and branched). Alkane molecules are nonpolar because all the bonds in alkanes are nonpolar. The differences in polarity and hydrogen bonding also explain the immiscibility of alkanes and other hydrocarbons with water. The main chemical property of alkanes is their low reactivity, which can also be attributed to the relative strengths of C-C and C-H bonds. The attractive forces between alkane molecules are stronger than the attractive forces between the alkanes and water. Deposits of wax are usually black; the texture of the material may vary from soft and sticky to hard and brittle. Wax deposits contain gums, resins, asphaltic material, crude oil, sand, silt, and, in many instances, water. They also vary in stability from a mushy liquid to a firm hard wax, depending mainly on the amount of oil present. The asphaltene content of wax is very

Precipitation of Particles in Oil Wells

43

small. The wax portion of paraffin usually consists of compounds containing 18–30 carbon atoms with molecular weights from 250 to 450 daltons; they have melting points of 100°F–140°F and form macrocrystalline solids. These crystals are typically large structures that tend to agglomerate. The microcrystalline solids form much smaller crystals; they consist of straight-chain compounds with carbon numbers of 40 to 60 and have melting points in the range of 140°F–190°F, as shown in Figure 8.

Figure 7. Asphaltene precipitation envelope on a P-T phase diagram.

Figure 8. Left: macrocrystalline paraffin. Right: microcrystalline paraffin.

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C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

During formation, paraffins with high melting points separate first, mixed with a number of waxes with lower melting points depending upon the extent to which the oil was cooled or evaporated while deposition occurred. When a waxy fluid is cooled below its cloud point, wax crystals form and begin to agglomerate. ASTM defines the cloud point of a crude oil as the temperature at which the paraffin particles start to precipitate from the solution and a cloud or cloudiness of paraffin crystals begins to appear in the crude oil. As the temperature is further reduced, crystal agglomeration reaches the point at which a loose gel structure is formed. This gel structure can be broken down by shear action but tends to reform on standing. The gel point occurs when the resting fluid cools below the pour point. The value of the gel point measures the solidification temperature and increases as the number of carbons increases [42-46]. The wax crystal is dependent on the crude oil, rate of cooling, and degree of agitation during cooling, among other variables. The precipitation of paraffins begins due to variations in the equilibrium conditions of the system generated by changes in pressure, temperature, or composition. Paraffin precipitation is associated with the onset of the formation of small solid crystals that create aggregates that separate from the fluid and subsequently cause increases in viscosity and/or deposition due to loss of solvency. The paraffinic crusts have Newtonian behavior above the cloud point, and thixotropic characteristics begin to appear below the cloud point due to precipitation of the crystals.

3.2. Precipitation of Paraffin Under the temperature, pressure, and crude oil composition conditions occurring in a reservoir, paraffin is soluble in crude oil. As the oil flows to the surface, the temperature, pressure, and amount of dissolved gases contained in the oil generally decrease. This decrease of temperature and gas breakout are factors resulting in the reduced solubility of paraffin in crude oil [47]. Figure 9 shows the properties that enable the study of paraffins within multicomponent mixtures of reservoir fluids.

Precipitation of Particles in Oil Wells

45

Figure 9. Properties of paraffin.

Table 4. Problems associated with paraffin

Problems of paraffin

Precipitation Deposition Migration of particles

Change of viscosity Reduction of porosity and permeability in flow channels Obstruction of flow channels

Understanding the behavior of the paraffinic compounds of reservoir fluids requires experimental tests and/or thermodynamic models that predict the coexistence of the solid phase with changes in the pressure and temperature of the system. In other words, a stability analysis must be performed under all production conditions, and the different problems from formation to the surface must be monitored [42, 45, 48, 49]. Table 4 shows potential problems associated with the precipitation and deposition of paraffin.

3.2.1. Stability of Paraffin Changes in temperature are considered to be the leading cause of paraffin precipitation; thus, paraffin properties are studied as a function of temperature. Usually, as the temperature increases, the solubility of the paraffin increases. There are several reasons why the fluid can cool from

46

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

the reservoir to the surface, resulting in depositions in piping. A cooling process can be related to the release of the gas from the reservoir, heat radiation to the system, temperature changes in the geothermal gradient, contact with the environment, etc. When a fast cooling rate is applied, the cloud point of the fluid decreases. At low cooling rates, the cloud point increases, resulting in an increase in the amount of precipitated paraffin. When the apparent molecular weight of the solution decreases, the temperature of the crystallization point decreases, which slows the precipitation of paraffins; thus, the presence of gas acts as a solvent and reduces the temperature of crystallization. In production processes where a rapid release of the light fractions of the fluid occurs, an increase in the temperature of the cloud point is generated, and the precipitation process occurs more quickly. For crude oils with low gas in solution (less than 50 mole %) and those that are subjected to low pressures, a decrease in the crystallization point is generated, but as the pressure increases above the bubble point, the crystallization point temperature increases. However, the behavior of the crystallization point with pressure depends on the fluid, for which individual evaluations must be performed. An example of a method to decrease the crystallization point involves increasing the pressure in the pipe by increasing the operating pressure of the separator. Figure 10 shows the results obtained by Won et al. [50], which illustrate the effects of pressure on the phase distribution of a synthetic crude oil with 41 components. The presence of light ends increases the solvent power of the oil for wax because the escape of gas decreases the ratio of solvent to solute. The presence of more compounds with high molecular weights generally improves wax solubility. The absence of these materials generally decreases wax solubility. After a decrease in solvency, the paraffin molecules seek a nucleus for subsequent crystal growth. Usually, the same paraffins, organic flakes, asphaltenes, water droplets, or grains of sand serve as nuclei for growth. This phenomenon is known as nucleation of paraffin.

Precipitation of Particles in Oil Wells

47

Figure 10. Effect of pressure in paraffin.

3.2.2. Mathematical Model of Precipitation of Paraffin Thermodynamic models provide information about the point at which the paraffinic constituents lose solvency and the amount lost in weight percentage. Precipitation in the models is derived from the chemical potential of the pure solid and the chemical potential of the pure liquid at the same pressure and temperature, while considering the melting properties determined by experimental tests of each of the models. Figure 11 describes a hypothetical process that is used to understand the behavior of interactions between liquids and waxes. Within this process, there is a change from a state “a” to a state “d.” To understand this behavior, it is useful to equip the system with thermodynamic properties and to analyze them through the system.

Figure 11. Analysis of an enthalpy system for a change from solid to liquid.

48

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala In the first stage, the system passes from state a with temperature T to 𝑓

state b with a temperature equal to that of fusion 𝑇𝑖 . The change in the heat capacity is represented by Equation 8: 𝑇

𝑓

𝑠 ∆𝐻𝑎𝑏 = ∫𝑇 𝑖 𝐶𝑝𝑖 𝑑𝑇

(8)

In the second stage, the system changes from state b to a state c, in which there is a change associated with the enthalpy, represented by Equation 9: 𝑓

∆𝐻𝑏𝑐 = ∆𝐻𝑖

(9)

In a later step, the solid material is cooled from a melting temperature to a temperature T. The system changes from state c to state d. The system undergoes a change in the caloric capacity of the solid. 𝑇

𝑙 ∆𝐻𝑐𝑑 = ∫𝑇 𝑓 𝐶𝑝𝑖 𝑑𝑇

(10)

𝑖

Then, the state changes from a to d: 𝑓

𝑇

𝑓

∆𝐻𝑎𝑑 = ∆𝐻𝑎𝑏 + ∆𝐻𝑏𝑐 + ∆𝐻𝑐𝑑 = ∆𝐻𝑖 + ∫𝑇 𝑖 ∆𝐶𝑝𝑖 𝑑𝑇

(11)

Analogously, the system can also be analyzed in terms of entropy. When performing a sub-stage study from state a to state b, Equation 12 is obtained: 𝑓

∆𝑆𝑎𝑑 =

∆𝐻𝑖 𝑓

𝑇𝑖

𝑓 𝑇 ∆𝐶𝑝𝑖 𝑑𝑇 𝑇

+ ∫𝑇 𝑖

(12)

The free energy is obtained as follows in Equation 13 and Equation 14: ∆𝐺 = ∆𝐻 − 𝑡∆𝑠

(13)

49

Precipitation of Particles in Oil Wells So, 𝑇

𝑓

∆𝐺𝑎𝑑 = ∆𝐻𝑖 (1 −

𝑓 𝑇𝑖

𝑇

𝑓

𝑓 𝑇 ∆𝐶𝑝𝑖

) + ∫𝑇 𝑖 ∆𝐶𝑝𝑖 𝑑𝑇 − ∫𝑇 𝑖

𝑇

𝑑𝑇

(14)

To perform the calculations, it is useful to study the behavior of the system in terms of fugacity. Thus, Equation 14 enables us to describe the change in Gibbs free energy in terms of the enthalpy. A more general expression is presented in Equation 15: 𝑑𝐺𝑖 = 𝑅𝑇𝑑 ln 𝑓𝑖

(15)

∆𝐺𝑎𝑑 = 𝑅𝑇(ln 𝑓𝑖0𝑙 (𝑝𝑟𝑒𝑓 ) − ln 𝑓𝑖0𝑠 (𝑝𝑟𝑒𝑓 )) = 𝑅𝑇 ln

𝑓𝑖0𝑙 (𝑝𝑟𝑒𝑓 ) 𝑓𝑖0𝑠 (𝑝𝑟𝑒𝑓 )

(16)

where 𝑝𝑟𝑒𝑓 is the pressure of reference and 𝑓𝑖0𝑙 and 𝑓𝑖0𝑠 are the fugacities in the liquid and solid reference states, respectively. If the molar volumes of the liquid and the solid are also assumed to be independent of the pressure, then 𝑓𝑖0𝑙 (𝑝) = 𝑓𝑖0𝑙 (𝑝𝑟𝑒𝑓 ) exp [

𝑣𝑖𝑙 (𝑝−𝑝𝑟𝑒𝑓 )

𝑓𝑖0𝑠 (𝑝) = 𝑓𝑖0𝑠 (𝑝𝑟𝑒𝑓 ) exp [

𝑅𝑇

]

𝑣𝑖𝑠 (𝑝−𝑝𝑟𝑒𝑓 ) 𝑅𝑇

]

(17)

(18)

Finally, replacing Equations 17 and 18 in Equation 16 gives the general expression that governs the behavior of waxes and enables thermodynamic calculations in precipitation. 𝑓

∆𝐻𝑖

𝑓𝑖0𝑠 (𝑝) = 𝑓𝑖0𝑙 (𝑝) exp [− 𝑓 𝑇𝑖

∫𝑇

∆𝐶𝑝𝑖 𝑇

𝑑𝑇 +

𝑅𝑇

∆𝑉𝑖 (𝑃−𝑃𝑟𝑒𝑓 ) 𝑅𝑇

]

(1 −

𝑇 𝑓 𝑇𝑖

1

𝑇

𝑓

) − 𝑅𝑇 ∫𝑇 𝑖 ∆𝐶𝑝𝑖 𝑑𝑇 + (19)

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C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

From Equation 19, the ideal solution model can be obtained, which enables calculation of the amount of paraffin precipitate in a liquid. ∆𝐻𝑖𝑓

𝑋𝑖𝑜 = exp [

𝑅𝑇

𝑇

(1 −

𝑓

𝑇𝑖

)]

(20)

where 𝑋𝑖𝑜 is the mole fraction of the paraffin solid in the oil. Another model requires knowledge of the solubility of the solid and the solubility of the liquid: ∆𝐻𝑖𝑓

𝑇

) + 𝜒 𝑖0 ]

(21)

− 𝛿0 )2 − (𝛿𝑖𝑠 − 𝛿𝑠 )2 ]

(22)

𝑋𝑖𝑠 = 𝑋𝑖𝑜 exp [

𝑅𝑇

(1 −

𝑓

𝑇𝑖

where 𝜒 𝑖0 =

𝑉𝑖0 [(𝛿𝑖0 𝑅𝑇

where 𝑋𝑖𝑠 is the mole fraction of the paraffin solid in the oil, 𝛿𝑖0 and 𝛿0 are the solubility parameters of the liquid in the ideal state and of the liquid at P and T, respectively, and 𝛿𝑖0 and 𝛿0 are the solubility parameters of the solid component in the ideal state and of the solid at P and T, respectively.

Figure 12. Paraffin precipitation envelope on a P-T phase diagram.

Precipitation of Particles in Oil Wells

51

Figure 13. Amounts of paraffin precipitate with increasing temperature at 14.7 psi.

The paraffin envelope shown in Figure 12 aids understanding of the coexistence between the solid phase together with the liquid and vapor phases. As can be seen in the upper region of the fluid stability zone, the liquid phase coexists with the waxes; in the instability region, the three phases coexist. Figure 13 shows the amount of paraffin precipitated as a function of temperature given isobaric conditions. The models generally estimate the paraffin content at ambient pressure.

4. FINES DEPOSITS 4.1. General Concepts Formation fines are very small particles of free solid material in the porous spaces of a reservoir. The fines are incorporated into the formation during geological deposition, drilling, and completion operations or can be released by acid stimulation processes that destroy the cemented material. The presence and migration of fine particles constitute one of the causes of formation damage during the production phase of a well. The

52

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

identified sources of fine particles in a hydrocarbon-producing formation can be classified as follows:   

External particles carried to the formation by injected fluids for completion, reconditioning, and recovery processes. In situ mobilization of particles due to drag forces and fluid rock interactions. Presence of particles in the formation from chemical reactions that cause organic and inorganic precipitations.

In a producing formation, two types of fines are usually found: fines related to clays and fines related to non-clay materials. The clay minerals correspond to hydrates of aluminum silicates whose structures contain tetrahedral and octahedral patterns. In a porous medium, there are four types of clays: smectite, illite, kaolinite, and chlorite. Each of these causes different problems in formation (swelling, deflocculation, and mobilization, respectively). Thin clays, such as quartz and feldspar, are removed by displacement of the humectant phase and by high velocity in the porous medium. Removal and subsequent deposition of these fine particles produces a gradual decrease in the flow capacity of the rock and a progressive reduction of the production capacity and/or injection of the formation. Oil formations contain fine clay particles that can expand by absorbing fluids that are not initially contained in the medium. The generated effect consists of a reduction of the flow channels by swelling of clays or dispersion and release of fine materials capable of migrating through the fluid. The fine particles move along the tortuous flow channels in the medium and at some point are retained and deposited on the porous matrix, alternating the porosity and permeability. Particle processes are shown in Figure 14 and can be classified into two groups: internal and external processes. External processes occur on the face of training. The internal processes occur in the porous medium and can be classified into three groups according to Civan [59]:

Precipitation of Particles in Oil Wells

53

Figure 14. Particle processes in porous media.

  

Processes on the surface of the pore: Deposit and removal. Processes in the throat of the pore: Blocking and unblocking. Processes in the total volume of the pore: In situ formation and disappearance of cake, migration, appearance and disintegration (chemical reactions, release of fine particles by chemical dissolution of the cement, coagulation or disintegration).

The phenomenon of migration is associated with the hydrodynamic forces present in the humectant phase where the fines move [51]. Critical velocity is defined as the point at which the surface contact forces are exceeded and particles begin to move [52, 53]. The fine particle is initially in equilibrium on the surface of the grain; forces such as van der Waals attractions, Born repulsive forces, the double-layer phenomenon, and hydrodynamic forces allow the particles to detach and interact with the fluid [54]. Changes in salinity, flow velocity, pH, residual oil saturation, temperature, wettability, oil polarity, and fractional flow of water and oil affect the production of fines in the formation [51, 55-57]. The behavior of these variables is of particular interest because it relates the mobilization of fines to the impact on the permeability of the formation. A good approximation of the phenomenon enables identification of the risk of

54

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

damage by fine migration or quantification of the excessive production of fines in the producing well. Fine damage involves multiple parameters and different processes generated by the production of the reservoir: 











High flow rates: for each formation, there is a critical velocity that is considered to be sufficient to cause the movement and detachment of fines. Distribution of pore sizes and particles: Particles whose size is one third or more of the pore size cannot enter the porous medium. These particles can stop at the inlet and form a filter cake. Particles whose size is between one third and one seventh the size of the pore throat tend to create bridges, especially when they enter the pore simultaneously. Particles smaller than one seventh of the groove width can be transported with the fluid or deposited on the walls of the pores due to the actions of different forces. Wettability: The fines flow with the wettable fluid. The wettable fluid is usually set as water; therefore, the presence of this fluid tends to cause fines to flow. Ionic exchange: A decrease in salinity represents an increase in pH due to ion exchange. A high pH indicates a greater potential for an increased amount of fines present on the surface until their dislocation and subsequent release. Two-phase flow: Turbulence can cause destabilization of fines, especially in the region near the well where these effects are considered to be greater due to radial flow. Acidification treatments: Incorrect acidification or incorrect treatment volume can result in precipitation, clay fragmentation, and de-consolidation due to excessive dissolution of the matrix.

4.2. Precipitation of Fines Formation damage occurs when reservoir fluids that flow through the porous medium release solid particulate material and deposit it upstream,

Precipitation of Particles in Oil Wells

55

preferably in the area near the bottom of the well. The fine material accumulates and obstructs the passage of fluids; the porosity of the rock decreases, and the permeability decreases. This phenomenon is known as formation damage by fines flow or formation damage by particle processes. Figure 15 describes three phenomenological mechanisms associated with permeability change.

4.2.1. Stability of Fines Fines migration can also be induced by mechanical entrainment of fines, which can occur when the fluid velocity is increased above critical velocity. Gruesbeck and Collins [51], among others, have measured the critical velocity for sandstones. Typical reported values of critical velocities are in the range of 0.02 m/s. This translates into modest well flow rates for most oil and gas wells. Below the critical velocity, no significant formation damage occurs because no thinning occurs. Above the critical velocity value, the velocity of removal increases with the rate of flow. It is deduced that the ratio between the rates of dragged fines is linear with the flow rate. The critical velocity of fines mobilization exists above the point where the shear or pulling force of the fluid can separate particles with weak adhesion to the porous surface [58]. Above the critical velocity, the fines can move through the pores with the fluid and can form bridges in the porous constraints or in the pore grooves by mechanical conditions, which causes clogging and therefore a decrease of the flow capacity of the formation. Knowing the critical velocity enables optimization of the rate of production or injection of a hydrocarbon well, which helps to prevent or reduce damage by fines migration. For this reason, velocity is considered to be a key factor in modeling damage by particle phenomena. The critical rate can be measured in the laboratory and escalated to field conditions. The test is based on measuring the permeability of the sample at different injection rates. The velocity or flow rate where the permeability decreases by 10% of its initial value is considered to be the critical rate.

56

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

Figure 15. Mechanisms of damage associated with the phenomenology of the fine particle migration process.

The experimental test consists of displacement of fluids in a forming core or in a sand packing that represents the characteristics of the deposit. The sample must be characterized by its petrophysical properties of porosity, base permeability, and lithology. The procedure can be summarized in the following steps: 1. The system is subjected to constant velocity injection of a fluid with known physical and chemical properties, such as viscosity, density, fines content, and pH. 2. The output condition of the system is set at constant pressure. As the injection rate does not change, the inlet pressure increases as a result of the reduction of porosity and permeability of the porous medium by the deposition of fines in the rock. 3. The process continues with the injection of porous volumes of fluid until the pressure profile does not change or the permeability of the system remains stable over time. The assembly of the experimental sample is presented in Figure 16.

Precipitation of Particles in Oil Wells

57

Figure 16. Experimental assembly of the displacement test.

4. The injection rate is increased to measure the new permeability associated with the flow rate. 5. When the measurement of the permeability at a given rate decreases by more than 10% compared to the previous rate, it is assumed that the fines have been mobilized and have plugged the porous medium, which causes damage to the sample. This injection rate is associated with the critical particle entrainment rate, as shown in Figure 17. 6. The permeability is measured at flow rates greater than the critical rate to analyze the effects of the sample damage.

Figure 17. Measurement of water permeability at various flow rates: case study.

58

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

Field scaling of the critical velocity is performed assuming that the properties of porosity and permeability in the reservoir are similar to the properties of the laboratory, i.e.,: 𝜙𝐿𝑎𝑏 = 𝜙𝑅𝑒𝑠 ; 𝐾𝐿𝑎𝑏 = 𝐾𝑟𝑒𝑠

(23)

Then, the critical rate corresponding to the reservoir conditions takes the form of Equation 24: 𝑄𝑅𝑒𝑠 [𝑆𝑇𝐵/𝑑] = 9.057 ∗ 10−3

2∗𝑄𝑙𝑎𝑏 ∗5.615∗𝑟𝑤 ∗ℎ 2 𝑟𝑙𝑎𝑏

(24)

where 𝑄𝑙𝑎𝑏 [cc/min] is the critical rate measured in the laboratory, 𝑟𝑤 [ft] is the radius of the well, 𝑟𝑙𝑎𝑏 [in] is the radius of the core, and ℎ [ft] is the height of the formation. Applying the velocities obtained in Equation 24 gives the value of the step velocity of flow in the reservoir. The critical velocity, as illustrated in Figure 18, separates the regions of damage due to migration and fine particle tamping. In a production history, it is possible to identify the migration times and the generation and swelling of fines. Figure 19 shows the behavior of the fines above and below the critical rate in a producing well.

Figure 18. Scaling of the critical rate from the laboratory to the reservoir.

Precipitation of Particles in Oil Wells

59

Figure 19. Production history and critical rate of a producing well.

4.2.2. Mathematical Model of Deposition of Fines Civan et al. (1990) [59] developed the phenomenological model that describes all the phenomena that govern particle processes based on fundamental conservation laws. They considered the combination of swelling effects with migration and retention of fine particles in porous media during flow to predict the reduction of permeability. The model includes the swelling and capture of clay particles from the surface of the pores by the shear of the fluid. It considers two different sources of particles: those generated inside the porous medium and those previously deposited, originating from the flow of particles in suspension. This model assumes liquid-particle biphasic flow. The fluid is considered to be incompressible and flows through pore grooves interconnected with a log-normal distribution. The model starts from the material balance in a cylindrical porous volume where flow only occurs in the direction perpendicular to the radial [58, 59]. The balance yields the fluid-particle two-phase flow equation: 𝜕 𝐾 𝜕𝑃 ( ) 𝜕𝑥 𝜇 𝜕𝑥

=

𝑆̇ 𝜌𝑙

+

1 𝜕 (𝜎𝑝 𝜌𝑝 𝜕𝑡

+ 𝜎𝑝∗ ) +

𝜕∅ 𝜕𝑡

(25)

In the previous equation, we have two parameters, 𝜎𝑝 and 𝜎𝑝∗ . The first parameter is called the deposition rate of fines. This parameter can be calibrated experimentally and can be assumed to be constant in tranches for practical purposes and simplification of the model. The second

60

C. Herrera Perez and M. Ruiz Serna and Richard D. Zabala

parameter, known as the in situ fines generation rate, can be assumed to be constant and is considered to be a typical parameter for each formation. 𝑆̇ represents the net adsorption rate. 𝜌𝑙 and 𝜌𝑝 are the densities of the liquid and particles, respectively. With the previous model, the effects of swelling, deposition, and in situ generation on the decrease of porosity are considered: ∅ = ∅𝑜 − ∅𝑝 − ∅𝑆𝑤

(26)

where ∅𝑜 is the initial porosity, ∅𝑝 corresponds to the decrease of porosity by deposition, and ∅𝑆𝑤 corresponds to the decrease of porosity by swelling. The decrease in permeability is calculated by 𝑘 𝑘𝑜

∅ 3 ∅𝑜

( )=( )

(27)

The system of equations of the mathematical model presents high nonlinearity. The model must be solved simultaneously using implicit methods in finite differences. The finite difference approximation, used to solve the equations of pressure and concentration of particles, generates a tridiagonal system that can be solved by the Thomas algorithm.

Figure 20. Multi-rate test fit with the linear Civan model for a laboratory sample.

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61

Figure 21. Risk map for statistical analysis of the risk of formation damage.

For each of the flows, the Civan model is executed, and we proceed to analyze the variation of the phenomenological constants over time. To facilitate the process, the test is divided into three sectors that are distinguishable according to speed: before the critical rate, during the critical rate, and after the critical rate. Figure 20 shows the behavior of the phenomenological constants at each of the injection rates in a laboratory sample.

5. DIAGNOSTICS AND LEVELS OF RISK OF FORMATION DAMAGE A risk map identifies the variables involved in the deposition of asphaltenes and prioritizes through statistical analysis the variable that produces the highest deposition rate. Figure 21 shows a typical risk map. In each of the quadrants, a degree of risk is assigned to the deposition of asphaltenes; on the X axis, the value provides the scale of impact on the formation damage. The variables located in quadrants I and II require particular attention because they represent a high probability of depositing asphaltenes. If the study variables are in quadrants III and IV, the

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sensitivity should be monitored to identify possible risks of changes in operational variables. The multiscale procedure allows scaling of experimental data or adjusted laboratory data to radial reservoir systems with large drainage areas to evaluate the impact of asphaltene deposition on formation damage in producing wells. As the methodology is implemented, variables such as porosity, permeability, and fluid velocity as well as the concentration of asphaltenes, concentration of paraffin, and content of fines in the liquid and rock are calculated; these describe characteristic behaviors according to the deposition phenomenology. Figure 22 shows a schematic illustrating the steps of the particle deposition damage scaling methodology in a formation using the prediction model.

Figure 22. Methodology for the diagnosis of asphaltene deposition formation damage.

The first point of the methodology enables evaluation of the information and data necessary for the linear and radial models. The second point performs the first diagnosis in the laboratory tests and calibrates the mathematical model with phenomenological constants calculated using statistical models. The last point shows the procedure to be followed to evaluate the behavior of fines in the reservoir and to diagnose formation damage and its effects on oil production. The preparation of data is perhaps the most important step in the methodology because it not only enables filtering of the information necessary for the simulation but also knowledge of the expected behavior of fines in the reservoir. For data preparation, it is recommended to organize an information matrix where the cells record the availability of

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the information and the main characteristics of the asphaltenes, waxes, and fines. 









Mineralogy describes the type of fines present in the formation, the physical and chemical features of the particles, and the fraction of dissolved particles estimated by statistical analysis. Permeability curves are indicative of the behavior of solid particles in the porous medium; in this model, it is a priority to know the experimental data of a displacement test in which the change of permeability with the time or the volume injected is recorded. The concentration of fines, asphaltenes, and paraffins can be obtained by mass balances in the formation fluids and the rock matrix, and the supposed fractions are obtained based on laboratory tests that show similar behaviors. The reservoir information comprises the numerical data of the properties of the fluid and reservoir rock, mainly the porosity and permeability values. The production history feeds the model with historical data on reservoir production rates.

ACKNOWLEDGMENTS The authors acknowledge the Universidad Nacional de Colombia for logistical and financial support. The authors also would like to thank Ecopetrol for granting permission to present and publish this chapter.

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González, G; Marcia, A. Sousa; Elizabete, F. Lucas. Asphaltenes Precipitation from Crude Oil and Hydrocarbon Media. Energy Fuels, 2006, 20 (6), p. 2544–2551. [3] Leontaritis, KJea. Asphaltene Deposition: A Comprehensive Description of Problem Manifestations and Modeling Approaches, in SPE Production Operations Symposium. 1989, Society of Petroleum Engineers: Oklahoma City, Oklahoma. [4] Ashoori, S; Ali, Abedini; Hadi, Saboorian; Khadijeh, Q. Nashegui; Reza, Abedini. Mechanisms of Asphaltene Aggregation in Toluene and Heptane Mixtures. Journal of the Japan Petroleum Institute, 2009, 52(5), p. 283-287. [5] Serguienko, SR; Davydov, BE; Delonfi, IO; Teterina, MP. Composition and Properties of High Molecular Petroleum Compounds. 1955. [6] Ahmed, T. Reservoir Engineering Handbook Third Edit. 2006. [7] Speight, JG. Handbook of Petroleum Product Analysis. 2002. [8] Akbarzadeh, K; Ahmed, Hammami; Abdel, Kharrat; Dan, Zhang. Asphaltenes — Problematic but Rich in Potential. Oilfield Review, 2007., 19(2), p. 22-43. [9] Mullins, OC. The Asphaltenes. Annual Review of Analytical Chemistry, 2011, 4, p. 393-418. [10] Zendehboudi, S; Ali, Shafiei; Alireza, Bahadori; Lesley, A. James; Ali, Elkamel; Ali, Lohi. Asphaltene precipitation and deposition in oil reservoirs – Technical aspects, experimental and hybrid neural network predictive tools. Chemical Engineering Research and Design, 2014, 92(5), p. 857-875. [11] Andersena, SIaJGS. Thermodynamic models for asphaltene solubility and precipitation. Journal of Petroleum Science and Engineering, 1999, 22(1-3), p. 53-66. [12] Buenrostro-Gonzalez, E; Henning, Groenzin; Carlos, Lira-Galeana; Oliver, C. Mullins. The Overriding Chemical Principles that Define Asphaltene. Energy Fuels, 2001, 15(4), p. 972-978.

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[37] Qin, X; Peng, Wang; Kamy, Sepehrnoori; Gary, A. Pope. Modeling Asphaltene Precipitation in Reservoir Simulation. Industrial & Engineering Chemistry Research, 2000, 39(8), p. 2644-2654. [38] Li, ZaAF. Cubic-Plus-Association Equation of State for Asphaltene Precipitation in Live Oils. Energy Fuels, 2010, 24(5), p. 2956-2963. [39] Ma, QaGC. Prediction of vapor-liquid-liquid-hydrate phase equilibrium for multicomponent systems containing tetrahydrofuran. Science China Chemistry, 2013, 56(12), p. 1800-1810. [40] Negahban, S; Paul Willhite, G; Wales, SM. Modeling of Three-Phase Liquid/Liquid Equilibria. Society of Petroleum Engineers, 1988, 3(03), p. 1017-1024. [41] Omidkhah, MR; Mohammad, Nikookar; Gholam, R. Pazuki; Leili, Sahranavard; Mohammad, A. Emadi. Calculation of Phase Behavior of Asphaltene Precipitation by Using a New EOS, in Abu Dhabi International Petroleum Exhibition and Conference. 2006, Society of Petroleum Engineers: Abu Dhabi, UAE. [42] Chung, F; Partha, Sarathi; Ray, Jones. Modeling of Asphaltene and Wax Precipitation. 1991, National Inst. for Petroleum and Energy Research: Bartlesville, OK (USA). [43] Ghanaei, E. Feridun Esmaeilzadeh and JamshidFathikalajahi., Wax formation from paraffinic mixtures: A simplified thermodynamic model based on sensitivity analysis together with a new modified predictive UNIQUAC. Fuel, 2012, 99, p. 235-244. [44] Lee, HS. Computational and Rheological Study of Wax Deposition and Gelation in Subsea Pipelines, in Chemical Engineering. 2008, The University of Michigan. [45] Lira-Galeana, C; Firoozabadi, A; John, M. Prausnitz. Thermodynamics of wax precipitation in petroleum mixtures. AIChE Journal, 1996, 42(1), p. 239-248. [46] Zuo, JY; Dan, D. Zhang; Heng-Joo, Ng. An improved thermodynamic model for wax precipitation from petroleum fluids. Chemica Engineering Science, 2001, 56(24), p. 6941-6947.

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[47] Barker, KM; Newberry, ME; Yin, YR. Paraffin Solvation in the Oilfield, in SPE International Symposium on Oilfield Chemistry. 2001, Society of Petroleum Engineers: Houston, Texas. [48] Dalirsefat, RaFF. A thermodynamic model for wax deposition phenomena. Fuel, 2007, 86(10-11), p. 1402-1408. [49] Aiyejinaa, A; Dhurjati, P. Chakrabartia; Angelus, Pilgrima; Sastry, MKS. Wax formation in oil pipelines: A critical review. International Journal of Multiphase Flow, 2011, 37(7), p. 671-694. [50] Won, KW. Thermodynamics for solid solution-liquid-vapor equilibria: wax phase formation from heavy hydrocarbon mixtures. Fluid Phase Equilibria, 1986, 30, p. 265-279. [51] Gruesbeck, CaREC. Entrainment and Deposition of Fine Particles in Porous Media. Society of Petroleum Engineers, 1982, 22(6), p. 847856. [52] Miranda, RMaDRU. Laboratory Measurement of Critical Rate: A Novel Approach for Quantifying Fines Migration Problems, in SPE Production Operations Symposium. 1993, Society of Petroleum Engineers: Oklahoma City, Oklahoma. [53] Ochi, JaJFV. A two-dimensional network model to simulate permeability decrease under hydrodynamic effect of particle release and capture. Transport in Porous Media, 1999, 37(3), p. 303-325. [54] Moore, EW, Crowe, CW; Hendrickson, AR. Formation, Effect and Prevention of Asphaltene Sludges During Stimulation Treatments. Journal of Petroleum Technology, 1965, 17(9), p. 1023-1028. [55] Khilar, K., Vaidya, RN; Fogler, HS. Colloidally-induced fines release in porous media. Journal of Petroleum Science and Engineering, 1990, 4(3), p. 213-221. [56] Okabe, H; Satoru, Takahashi; Hiroshi, Mitsuishi. Distribution of Asphaltene Deposition in the Rock Samples by Gas Injection, in Abu Dhabi International Petroleum Exhibition and Conference. 2010, Society of Petroleum Engineers: Abu Dhabi, UAE. [57] Sarkar, AKaMMS. Fines Migration in Two-Phase Flow. Journal of Petroleum Technology, 1990, 42(5), p. 646 - 652.

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[58] Civan, F. Formation Damage Mechanisms and Their Phenomenological Modeling—an Overview, in European Formation Damage Conference. 2007, Society of Petroleum Engineers: Scheveningen, The Netherlands. [59] Civan, F. A generalized model for formation Damage by rock_fluid interactions and Particulate Processes, in SPE Latin America Petroleum Engineering Conference. 1990, Society of Petroleum Engineers: Rio de Janeiro, Brazil.

In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 3

NANOPARTICLE FABRICATION METHODS Esther Bailón-García*, Agustín F. Pérez-Cadenas, Elizabeth Rodríguez-Acevedo and Francisco Carrasco-Marín† Research Group in Carbon Materials, Inorganic Chemistry Department, Faculty of Sciences, University of Granada, Campus Fuente Nueva, Granada, Spain

ABSTRACT Nanotechnology has brought with it a variety benefits to humanity, especially in the biomedical and electronic fields. In the oil-and-gas industry, nanoparticles have been used in processes ranging from upgrading and transportation to viscosity reduction. The most interesting properties of nanoparticles are their higher surface areas, small size, and optically, magnetically, and electrically tunable properties. In this chapter, it is presented the methodologies used in the synthesis of nanoparticles, which can be either bottom-up or top-down. * †

Corresponding Author Email: [email protected]. Email: [email protected].

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E. Bailón-García, A. F. Pérez-Cadenas et al. The first method builds particles by the use of atoms or molecules and the second starts with large material nanoparticles produced by different processes. In this text, it is discussed also the historical materials and methods used in the synthesis of carbon-based nanomaterials, review their properties, and describe the different types of carbon nanomaterials. Also, the procedures employed with respect to metallic, bimetallic, and ceramic nanomaterials are presented, including the colloidal method, photochemistry and radiochemistry reduction, microwave radiation, and sol–gel method.

Keywords: nanoparticle synthesis, bottom-up, top-down, nanomaterial

1. INTRODUCTION The enormous growth in the world population, rising living standards, and increasing energy demand in developing countries has brought serious challenges to the oil-and-gas industry as it tries to meet the corresponding growing energy demand. Conventional resources, exploration, and production techniques might not be sufficient to do so, which makes it necessary to identify new energy supplies from natural resources or to enhance the recovery of systems currently in place. The use of renewable energies such as solar power, wind power, hydropower, and biomass or geothermal energy are being extensively pursued and implemented worldwide. However, these energy resources cannot yet meet the escalating energy demand. As such, the enhancement of in-situ recovery, increased productivity, and upgrades in oil/gas technologies is necessary [1, 2]. Nanotechnology offers many potential solutions to the problems faced by industry that cannot be solved using conventional technologies [1] and which may benefit a range of aspects in the oil-and-gas industry, including exploration, production, drilling, refining, and distribution. For example, nanosensors could provide more detailed and accurate information about reservoirs [2], nanomaterials can be used to manufacture harder and more durable drilling equipment [3], nanocatalysts can be designed for on-site

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field upgrades, and, as noted above, nanofluids can be designed for enhanced oil recovery [4, 5]. By convention, nanoparticles range between 1 nm and 100 nm in size in at least one of the three Cartesian directions, there being 0-, 1-, and 2dimensional nanomaterials. However, in nanotechnology, a nanoparticle is more specifically defined as a small entity that behaves as a whole unit with respect to its physicochemical properties. In size, ultrafine particles are the same as nanoparticles—between 1 nm and 100 nm in size. Fine particles are defined as being between 100 nm and 2500 nm in size and coarse particles range between 2500 nm and 10000 nm. Although nanotechnology is considered to be a modern scientific development and has received a lot of scientific attention over the past six decades, nanomaterials and nanotechnology have always existed naturally in proteins, polysaccharides, and viruses, to name a few. Nanoparticles were also used in Mesopotamia during the 9th century in ceramic glazed decoration [6]. Nanoparticle and nanotechnology research is currently an area of intense scientific interest due to a wide variety of potential applications in biomedical, optical, and electronic fields. In oil/gas processing and upgrading industries, nanoparticles are used and are the subject of research for a variety of different processes. For natural gas [7], this includes processes such as catalytic reforming [8, 9], Fischer-Tropsch synthesis [10, 11], oxidative coupling [12, 13], and catalytic combustion [14], among others [15, 16]. In oil processing, nanotechnology is being applied to catalytic cracking [15], in-situ combustion [17], thermal cracking [18], magnetic transportation [19], viscosity reduction [19, 20], hetero-atoms removal [21], and formation damage [19], among others [19, 22]. The synthesis or preparation of nanoparticles can be divided into two methodology categories: bottom-up and top-down. The first relates to methodologies that built nanoparticles from individual atoms, and the second, top-down, relates to methodologies that begin with mechanical/physical methods, such as grinding or pulverizing. These methods can also be identified by the media used during preparation [23, 24], or the solid, liquid, gas [25], or plasma phases [24, 25], each of which

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produce nanoparticles in different states, including supported [24], suspended [24, 26], powdered, and embedded [24].

2. MATERIALS AND METHODS 2.1. Top-Down Top-down methodologies have limitations related to the fact that as particle size decreases, chemical reactivity increases, which eventually leads to the back reaction of particles, necking, and coalescence [24, 27]. Thus, it consider the extreme of water droplets, these droplets never spontaneously split apart, but do spontaneously coalesce to form larger droplets. The same applies to metal droplets and solid particles. Because of their increased surface energies and reactivities, grinding and pulverization are not appropriate methods for reaching sizes below 50 nm, and they are certainly not suitable for attaining monodispersity (all particles of the same size). The most satisfactory results are realized for solids with very high lattice energies, such as magnesium oxide and other ceramics. The least favorable results are realized by low melting, low lattice energy solids, such as zinc metal or magnesium metal. One modification that helps to stabilize small particles as they form is the addition of an active surface ligand, which is referred to as chemo-modified grinding. However, even this approach has not proven to be very successful in rigorous studies. Nonetheless, if large amounts of nanomaterials are needed, and there is no requirement for monodispersity or ligand stabilization, the grinding/pulverization of bulk solids is a viable synthetic method [24].

2.1.1. Reactive Grinding/Ball Milling Reactive grinding is probably one of the most intuitive methodologies for reducing particle size. Industrially, this process is known for reducing grain size and providing a more reactive surface, for example, by mineral processing or metal extraction [28]. Reducing size and increasing surface area is one of the objectives for obtaining nanoparticles. However, the

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overall free-energy change, ∆𝐺, is the sum of the free energy due to the new volume and that due to the newly created surface. For spherical particles, the free-energy change can be expressed as follows: 4 𝑉

∆𝐺 = − 𝜋𝑟 3 𝑘𝐵 𝑇 + 4𝜋𝑟 2 𝛾

(1)

where 𝑉 is the molecular volume of the new species, 𝑟 is the radius of the nuclei, 𝑘𝐵 is the Boltzmann’s constant, and 𝛾 is the surface free energy per unit surface area. In Eq. (1), we can see that ∆𝐺 is more negative since the volume is bigger. In all of the methodologies for preparing nanoparticles, the key is to stabilize the surface and reduce the surface free energy. In high-energy ball mills (HEBM), balls are confined in a closed container together with powders to be mechanically processed and are in permanent relative motion with speeds of several m∙s−1. Kinetic energy is transferred to the powders trapped between colliding balls, or between the inner surface of the container and a moving ball. In the HEBM process of producing powder mixtures, trapped particles are subjected to high stresses (on the order of 200 MPa for steel balls, and higher for materials of other densities such as tungsten carbide), which most often exceed their mechanical strength, for periods of time on the order of microseconds, along with a temperature rise [24]. The waiting period between these efficient trapping events is typically on the order of tens to hundreds of seconds. The morphological evolution of ground powders strongly depends on the mechanical properties of the components of the initial mixture, which evolve during milling [25, 29]. A balance between coalescence and fragmentation is most often achieved during HEBM, which leads to a rather stable average particle size. The temperature increase in the powders during HEBM is difficult to determine either theoretically or experimentally. but is believed to be some hundreds of degrees for metallic powders ball-milled in the conditions typical of laboratory planetary ball mills. Also, mechanical stresses applied during milling to grind powders can produce different kinds of defects, depending on the dynamic milling conditions and on the mechanical properties of the ground materials [29]. Other milling parameters also contribute to the transformations of powders,

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including the ball-to-powder weight ratio, the nature of the milling media, the milling atmosphere, the precursor, and the type of mill [30]. Figure 1 illustrates the interactions that take place during the high-energy ballmilling process.

Figure 1. High-energy ball-milling process [31].

2.2. Bottom-Up 2.2.1. Solvothermal The term solvothermal comes from the original process known as hydrothermal [32]. The definition of hydrothermal has undergone several changes from its original Greek hydros meaning water and thermos meaning heat [33]. Recently, Byrappa and Yoshimura [34] defined hydrothermal as any heterogeneous chemical reaction in the presence of a solvent (aqueous or non-aqueous) above room temperature and at a pressure greater than atmospheric in a closed system [34]. However, there is still some ongoing discussion about the usage of the term hydrothermal. For example, chemists prefer to use the term solvothermal to mean any

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chemical reaction in the presence of a non-aqueous solvent in supercritical or near-to-supercritical conditions [32, 35]. Similarly, there are several other terms such as glycol thermal [36], alcohol thermal [37, 38], and ammonia thermal [35, 39], among others [40]. Furthermore, researchers working in the supercritical region in investigations of materials synthesis, extraction, degradation, treatment, alteration, and phase equilibria prefer to use the term supercritical technology [35]. Solvothermal may be the most appropriated term for processes in which systems are submitted to high pressures and temperatures near or above the critical point [41]. The solvothermal processing of advanced materials has many advantages and can be used to produce high product purity and homogeneity, crystal symmetry, meta-stable compounds, and narrow particle size distributions at lower sintering temperatures for a wide range of chemical compositions, in single-step processes, with dense sintered powders and submicron and nanoparticles with a narrow size distribution. In addition, this process requires only simple equipment and lower energy requirements and is characterized by fast reaction times, the lowest residence times, and the growth of crystals with polymorphic modifications and with low to ultra-low solubility, as well as a host of applications [34, 42]. The intrinsic properties of nanoparticles strongly depend upon their morphology and structure. The synthesis and study of these nanoparticles has implications for the fundamental study of the crystal growth process and shape control [43, 44]. Solvothermal techniques have been extensively used in the preparation of nanoparticles [42, 45]. These techniques there have been reported to have been used in the synthesis of differently shaped nanostructures and in different oxidation states. Wang et al. [46] reported the synthesis of SrCO3 dendrites using a simple hydrothermal methodology. Various dendrites have also been obtained by hydrothermal methodologies. Single nanoparticles such as nanospheres, nanoplates, and nanocrystals are the most common nanomaterials produced by this process. In solvothermal synthesis, variables such as temperature, pressure, and reaction time are the most studied conditions. However, other important variables include the nature of the solvent, the concentration of the

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regiments, the surfactants, templates, and pH, among others [19, 47]. Figure 2 illustrates the process of solvothermal synthesis.

Figure 2. Process of solvothermal synthesis [47].

2.2.2. Precipitation and Co-Precipitation The kinetics nucleation and particle growth in homogeneous solutions can be adjusted by the controlled release of anions and cations [48, 49]. Careful control of the precipitation kinetics can result in monodispersed nanoparticles. Once the solution reaches a critical supersaturation of the species-forming particles, only one burst of nuclei occurs. Thus, it is essential to control the factors that determine the precipitation process, such as the pH and the concentration of the reactants and ions. Organic molecules are used to control the release of the reagents and ions in the solution during the precipitation process. The particle size is influenced by the reactant concentration, pH, and temperature [48]. By optimizing these factors, broad kinds of nanoparticles with narrow size distributions can be

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produced, including Zr(OH)4, BaTiO3, YBaCu3Oy, CdS, HgTe, HgTe, and CdTe [48]. Although using the precipitation method to prepare nanoparticles is very straightforward and simple, elaborate nanostructures can also be constructed using this methodology. This includes structures such as CdS/HgS/ CdS, CdS/(HgS)2/CdS, and HgTe/CdS quantum well systems and other core/shell structures [48].

2.2.3. Ultrasound-Assisted Nanoparticle Synthesis [50] Ultrasonic irradiation provides rather unusual system conditions short durations of extremely high temperatures and pressures in liquids that cannot be achieved by other methods [51]. Interestingly, these conditions are not derived directly from ultrasound itself, as the acoustic wavelengths are much longer than the molecular dimensions. Thus, no direct, molecular-level interaction between the ultrasound and the chemical species takes place. Instead, acoustic cavitation, formation, growth, and the implosive collapse of bubbles in liquids, driven by the high-intensity ultrasound, accounts for the chemical effects of ultrasound [5].

Figure 3. Schematic representation of transient acoustic cavitation [50].

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When liquids are irradiated with ultrasound, the alternating expansive and compressive acoustic waves create bubbles (cavities) and cause these bubbles to oscillate, as shown in Figure 3 [50]. These oscillating bubbles can effectively accumulate ultrasonic energy while growing to a certain size (typically tens of μm) [50]. Under the right conditions, a bubble can overgrow and subsequently collapse, which releases the concentrated energy stored in the bubble within a very short time period (with heating and cooling rates of > 1010 K∙s−1) [50]. This cavitational implosion is very localized and transient with a temperature of 5000 K and a pressure of 1000 bar [52]. The sonochemical reduction of metals has some advantages over other more traditional reduction methods (e.g., sodium borohydride, hydrogen, and alcohol) [52]. In this process, no chemical reducing reagent is needed, the reaction rates are faster, and very small metal particles can be produced [50]. The sonolysis of the solvents accounts for these sonochemical reductions. For example, the sonolysis of water can produce H∙ and OH∙ radicals, which are considered to be reductants and oxidants, respectively [53]. In other cases, organic additives are added to produce a secondary radical species, which can significantly enhance the redox rate. During the synthesis of oxides, chalcogenides, hydroxides, and other compounds, ultrasound radiation improves the precipitation rate and the various reaction rates in general, and can also be tuned up to achieve different morphological shapes, particles, and nanoparticles, with better narrow size distributions and larger surface areas [52].

2.2.4. Microwave-Assisted Nanoparticle Synthesis Microwave irradiation is electromagnetic radiation in the frequency range of 0.3–300 GHz, which corresponds to wavelengths from 1 mm to 1 m [54]. A large fraction of the microwave spectrum is reserved for telecommunication and radar technology applications [55]. All kitchen microwave ovens and a large majority of commercially available dedicated microwave reactors operate at a frequency of 2.45 GHz (corresponding to a wavelength of 12.25 cm) [54]. The choice of this frequency is the result of a compromise to fulfill several requirements. First, any interference with

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telecommunication, wireless networks, and cellular phones must be avoided [56]. Second, this frequency is perfect for kitchen microwaves, because the corresponding magnetrons can be produced at low cost, the 12.25-cm wavelength is shorter than dimensions of the cooking chamber, and the typical penetration depth in food is in the range of a few centimeters [56]. On the other hand, this frequency is not optimized for heating water, because liquid water has a much higher resonance frequency, 18 GHz, so the most effective conversion of microwave energy into thermal energy would occur in this frequency region [57]. Microwave physical-chemistry is based on the efficient heating of matter by microwave dielectric heating and on the ability of a particular material (solvent and reagents) to absorb microwave energy and then convert it into heat [58]. The heating mechanism involves two main processes—dipolar polarization and ionic conduction. Microwave irradiation of a sample results in the alignment of the dipoles or ions in the electric field. Because electromagnetic radiation produces an oscillating field, the dipoles or ions continuously attempt to realign themselves in the electric field. We note that the ionic conduction mechanism represents a much stronger effect than that of dipolar polarization with respect to the heat-generating capacity, and this has, of course, great consequences for the synthesis of nanoparticles in ionic liquids. Figure 4 shows the microwave dielectric heating process.

Figure 4. Microwave-assisted heating process [57].

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Two parameters define the dielectric properties of a substance: (i) the dielectric constant 𝜀’, which describes its ability to be polarized by the electric field, and (ii) the dielectric loss 𝜀’’, which indicates the efficiency with which electromagnetic radiation is converted into heat. The ratio of these two parameters defines the dielectric loss tangent 𝑡𝑎𝑛𝛿 = 𝜀’’/ 𝜀’. This loss factor provides a measure of the ability of a material to convert electromagnetic energy into heat at a given frequency and temperature [54]. A reaction medium with a high loss factor, i.e., with a high 𝑡𝑎𝑛𝛿 value, is required for efficient absorption and rapid heating [59]. Solvents are generally categorized into three groups according to their high, medium, and low microwave absorption properties. High microwaveabsorbing solvents typically have a tanδ > 0.5, whereas medium and low absorbing solvents have values of 0.1–0.5 and < 0.1, respectively [54]. Polyalcohols like ethylene glycol, 1,3-propanediol, 1,4-butanediol, and glycerol20 have high loss tangents, and are therefore suitable solvents for microwave chemistry synthesis. These polyol routes are frequently used in the microwave-assisted synthesis of metal-oxide and metal-chalcogenide nanoparticles [60, 61].

2.3. Synthesis of Carbon-Based Nanomaterials: History and Perspectives Nanomaterials are particles with sizes ranging from 1 nm to 100 nm in at least one of their three dimensions [62]. One of the most interesting aspects of nanomaterials are the properties these materials exhibit due to their small size. Nanomaterials have a higher surface area than the same materials at the macroscale and quantum effects may control the behavior of these materials at the nanoscale, thereby affecting their optical, magnetic, and electrical properties. These higher surface areas and quantum effects at nanoscales, compared with the same material at macroscales can produce significant property differences with respect to reactivity, hardness, and electrical conductivity, which makes these nanomaterials excellent for many applications.

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Due to their unique properties, many carbon nanomaterials have been studied in recent years, including nanodiamonds, fullerenes, carbon nanotubes, graphene, carbon nanofibers, carbon nanocones/disks and nanohorns, as well as their respective functionalized forms. Carbon fibers and filaments have been extensively studied since 1980 due to the high demand by the space and aeronautics industry. The discovery of fullerenes in 1985 by Kroto et al. [63], carbon nanotubes in 1991 by Iijima [64], and graphene in 2004 by Geim and Novoselov [65] brought a genuine scientific revolution to research worldwide and, consequently, has established the new research field of nanotechnology. The main advantages of these materials are their high surface-to-volume ratios and their excellent mechanical, thermal, and electronic properties, which has created expectations for many possible applications.

2.3.1. Graphene

Figure 5. Graphene.

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2.3.1.1. Structure and Properties Graphene can be considered to be the basic building block of all graphitic forms (including carbon nanotubes, nanohorns, and even graphite and fullerene). This single two-dimensional monolayer of carbon atoms is an sp2 hybridized carbon-based material with carbon atoms organized in purely hexagonal rings. The surface area of a single graphene sheet is theoretically as large as 2630 m2 g−1 [66] and both sides of the sheets are available for molecular adsorption without the steric hindrance of an adsorbate molecule, which make it an excellent adsorbent. Also, it possesses extraordinary properties, among which are a high electrical conductivity with a ballistic conduction of charge carriers (having an electrical conductivity 100 times higher than copper) [67, 68], optical properties (high optical transmittance of 97.7% and independent of the wavelength throughout the visible range) [69], high elasticity and high hardness (200 times higher than steel) [70], and high thermal conductivity (1.5 times higher than diamond) [71], which means that it can be integrated into a huge number of applications in biological engineering and optical electronics, specifically touchscreens, liquid crystal displays and organic light emitting diodes, photovoltaic cells, energy storage, ultrafiltration, and sensing, among others. Consequently, graphene is considered to be a highly promising material. The integration of these new materials in future technologies could make possible the creation of thinner, stronger, faster, and more flexible devices. So, it is now important to optimize methods for synthesizing graphene to obtain the quality required for each application and to increase production to the large scale while also making them costeffective. 2.3.1.2. Synthesis 2.3.1.2.1. Mechanical Exfoliation Graphite comprises stacked layers of many graphene sheets separated by 3.35 Å that are bonded together by weak van der Waals forces. As such, it could be possible to obtain graphene that could break these forces. Before Geim and Novoselov obtained graphene for the first time, scientists

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had described graphene layers and their theoretical properties. However, isolating a graphene sheet was unthinkable because it was thought to contain too many defects that made it unstable at room temperature. The first time graphene was artificially produced by mechanical exfoliation [68], scientists took a piece of graphite and separated it layer by layer using adhesive tape until only one single layer remained. Mechanical exfoliation produces graphene with the lowest number of defects and, consequently, the highest quality. However, due to its low-scale productivity, this method is limited to research investigations. 2.3.1.2.2. Chemical Exfoliation The idea behind this method is to increase the interlayer spacing between graphene sheets on the graphite structure and thereby reduce the interlayer van der Waals forces. This could be achieved by intercalating different types of compounds between the graphene sheets of graphite, and then exfoliating them into graphene by sonication or rapid heating. The most studied method for doing so is the oxidation of graphite to obtain graphene oxide (GO) and subsequent liquid exfoliation. This GO could be obtained by the strong oxidation of graphite using the Hummers method [72], which involves the oxidation of graphite with strong oxidizing agents such as KMnO4 and NaNO3 in H2SO4/H3PO4 to generate rough sheets with epoxide and hydroxyl groups on their basal planes, in addition to carbonyl and carboxyl groups that are presumably located at the edges. These functional groups increase the hydrophilicity, which leads water to readily intercalate between the sheets and thus reduce the interplanar forces, which facilitates exfoliation in graphite sheets by ultrasonication. However, the obtained sheets have a high density of functional groups so, subsequently, it is necessary to apply a chemical or thermal reduction to remove the covalent functional groups and produce reduced graphene oxide. Nonetheless, GO reduction inevitably leaves numerous defects and its electronic conductivity is only partially restored after several reduction steps, never achieving true graphene conductivity (compared with graphene obtained mechanically). Moreover, the oxidation/reduction process involves the use of hazardous and/or corrosive chemicals. As an

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alternative approach, another successful exfoliation method for obtaining materials with few defects is sonication-assisted liquid-phase exfoliation. This method consists of the dispersion of graphite powder in an appropriate organic solvent and the sonication of the mixture for a certain period of time [73]. Different organic solvents have been tested following this procedure and the best results have been obtained using solvents with similar surface tensions to that of graphite, such as N-methylpyrrolidone [73], dichlorobenzene [74] or benzylamine [75]. During ultrasonication, shear forces and cavitation [76], as well as the growth and collapse of the micrometer-sized bubbles or voids present in liquids due to pressure fluctuations, act on the bulk material and induce exfoliation. Then, centrifugation must be used to remove unexfoliated material, which usually requires long sonication times and, consequently, high-energy consumption together with low productivity as well as expensive solvents that require special handling. Also, longer times imply the reduction of the flake size, together with an increase in the number of defects, which affect the electronic properties of graphene. Research has shown that these defects are predominantly located at the edges of the graphene flakes, whereas the basal plane of the flakes is relatively flawless [77]. Although direct liquid-phase exfoliation offers several advantages, the amount obtained by this method is still low. Therefore, alternative liquid-phase processes capable of producing a reasonably high concentration of stable graphene suspension are highly desirable. In this regard, Bari et al. [78] recently synthesized ionic liquids containing aromatic groups on the imidazolium cation that non-covalently interact with graphene surfaces. This approach enables the dispersion of pristine graphene without covalent functionalization or an additive stabilizer. These dispersions are stable against aggregation and can exfoliate and stabilize high concentrations of pristine graphene sheets. On the other hand, the addition of naphthalene during liquid-phase exfoliation improves the production yield of graphene because the naphthalene serves as a “molecular wedge” that intercalates into the edge of the graphite and expands the interplanar space between adjacent graphitic layers during the sonication process [79].

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Other intercalation methods have also been studied and realized good results, including the intercalation of alkali metal ions, polymers, and surfactants [77, 80, 81]. Václav Štengl et al. [80] optimized a method based on the intercalation of a permanganate M2MnO4 (M = K, Na, Li) to exfoliate graphite. This novel exfoliation method is based on a process related to cavitation. As an example, the authors used KMnO4 and KOH, which react at elevated temperatures to form an unstable potassium manganate (K2MnO4). The K2MnO4, under ultrasonic waves, spontaneously decomposes into MnO2 to form an oxygen species that exfoliates graphite, as shown in Figure 6. Also, alkali metal ions have been intercalated in the bulk graphite structure to exfoliate graphene layers followed by dispersion in a solution. Previously, Viculis et al. [81] proved that alkali metals form graphite intercalation compounds. The authors reported that alkali metals react violently with water and alcohol to produce alkali metal ethoxide and H2, which then caused graphite exfoliation into graphene. So, a significant advance has been achieved in this field by a graphite exfoliation method with good productivity and scalability and moderate/high quality.

Figure 6. Chemical exfoliation method.

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2.3.1.2.3. Electrochemical Exfoliation Recently, high-quality graphene with a high yield has been obtained by the electrochemical exfoliation of graphite. This method basically consists of using graphite as an electrode and a source of graphene, a Pt wire as a grounded electrode, and an electrolyte, i.e., usually an inorganic acid such as HBr, HCl, HNO3, or H2SO4. Then, a positive voltage is applied to the graphite electrode to generate graphite exfoliation to produce graphene [82]. Various authors [83-85] have proposed that, first, the application of a voltage produces the oxidation of water, which generates hydroxyl (OH) and oxygen radicals (O). These radicals produce the oxidation or hydroxylation of the edge sites and grain boundaries of the graphite electrode and these defective sites at the edges or grain boundaries facilitate intercalation by anionic SO42-. This process leads to the release of gaseous SO2 and/or anion depolarization and causes the expansion of the interlayer distance in graphite. Consequently, exfoliation in acidic electrolytes can yield graphene with a better quality and a larger lateral size. However, it also produces excessive oxidation of graphite, which reduces the electronic properties of the as-prepared graphene. To lessen the degree of oxidation by H2SO4, KOH can be added to the H2SO4 solution to lower the acidity of the electrolyte solution [82]. The use of alternative electrolytes such as an ionic liquid or aqueous inorganic salts has also been studied [84, 86-89]. Parvez et al. [87] obtained a highly efficient electrochemical exfoliation of graphite in aqueous inorganic salts such as ammonium sulfate ((NH4)2SO4), sodium sulfate (Na2SO4), and potassium sulfate (K2SO4). This aqueous sulfate-salt-electrolyte solution effectively reduces the degree of oxidation and thereby significantly improves the chemical and electronic properties of the graphene. The use of an ionic liquid has also been studied. The mechanism proposed for this method is the same: (1) electrolysis of water at the electrode produces hydroxyl and oxygen radicals; (2) the oxygen radicals start corroding the graphite anode on the edge sites, grain boundaries, and defect sites, which results in the opening up of edge sheets; (3) the ionic liquid anions intercalate between the edge sheets and initiate electrode expansion and the exfoliation of some sheets results in the creation of graphene sheets dispersed in solution. The

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interplay between the electrolysis of water and the intercalation of ionic liquid ions is responsible for the production of the sheets [84, 86, 88, 89]. However, exfoliation in ionic liquids results in only a low yield of graphene with a small lateral size (< 5 μm). In addition it often functionalizes with the ionic liquids, which disrupt the electronic properties of graphene [84, 90, 91]. Figure 7 shows the setup for graphene electrochemical exfoliation.

Figure 7. Electrochemical exfoliation method.

2.3.1.2.4. Epitaxial Growth This technique is based mainly on the high-temperature decomposition (temperature above 1150ºC) of a silicon carbide under ultra-high vacuum or in an inert environment such as argon [92, 93]. At high temperatures, SiC bonds break and Si atoms sublimate from the substrate. With the removal of silicon atoms, the remaining carbon atoms nucleate and grow epitaxially to form a C-rich layer on the SiC surface. The use of vacuum conditions during epitaxial growth yields graphene with a rough surface, in which discontinuity and pits are formed [94]. To improve the graphene quality, argon (Ar) atmosphere is used to confine the sublimation of Si atoms and to provide enough time for the carbon atoms to diffuse and to promote the growth of large graphene domains [92, 95]. Moreover, a long time period is necessary for this growth due to the fact that epitaxial graphene on SiC is a conventional sublimation process and consequently

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dependent on the removal of Si from the surface by thermal evaporation reactions. As such, the control of the thickness of graphene layers is difficult due to the long time period required. As a consequence, the growth time must be reduced to improve the formation of the single-layer graphene sheets. In this regard, Rana et al. [96] tried to control graphene growth using Ar atmosphere together with a Si-selective etchant in the chamber, such as SiF4. SiF4 reacts only with the Si of the SiC substrate and efficiently removes Si from the surface as SiF2 and, consequently, enhances the Si removal process and lends more controllability to the conventional growth process. In the same way, Hu et al. [97] employed Pb atmosphere to yield high-quality, single-layer epitaxial graphene, whereby the Pb atmosphere retards Si sublimation so that the nucleated graphene domains grow more easily. At the same time, the metal atoms near the disordered C atoms weaken the C—C bonds to promote graphitization. Despite the high quality of the graphene obtained using this method, the required high processing temperatures and the high cost of the substrate makes this method specific to very particular applications such as circuits. 2.3.1.2.5. Chemical Vapor Deposition This type of graphene growth over the surface of transition metal film substrates such as Pd [98, 99], Ru [100, 101], Ni [102, 103], Ir [104-106], Cu [107], Co [108], and Pt [109, 110] is the most promising method for synthesizing high-quality graphene in industrial-scale quantities. During a typical chemical vapor deposition (CVD) experiment, the metal substrate, previously pre-treated (to clean its surfaces and modify the surface morphology, including the crystalline orientation, roughness, and grain size) is exposed to an atmosphere with a carbon source (hydrocarbon gas) at high temperature which produces gas decomposition, and the carbon atoms that form are attached to the metal, being either diffused or adsorbed onto the metal surface. Then the substrate is cooled to decrease the solubility of the carbon in the transition metal and a thin film of carbon is formed on the metal surface. Finally, the sheet is separated from the metal substrate, typically by the solution.

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We note that both a homogeneous gas phase and heterogeneous catalytic reactions can take place. The former primarily produces ultrafine powder whereas the latter primarily leads to the formation of a film. As such, heterogeneous chemical reactions should be favored and homogeneous phase avoided during the experiment design [111]. Moreover, the use of hydrogen together with a carbon source can affect the CVD process. This effect has been reported by various authors. Vlassiouk et al. suggested that hydrogen has a double role as an activator of surface-bound carbon that leads to monolayer growth and as an etching reagent that controls the size and morphology of the resulting graphene domains. These authors also found the growth rate maximum to be a function of the hydrogen partial pressure. Liu et al. [112] suggested that higher hydrogen flows favored the formation of graphene layers since the hydrogen would activate more hydrocarbon decomposition and increase carbon adsorption on the metal surface, thereby resulting in the formation of a continuous graphene film. Zhang et al. observed that, during the growth of graphene on a Cu substrate as a catalyst, depending on the pressure of the H2 gas, the graphene edges are either directly passivated by the Cu surface (at a low pressure) or terminated by H atoms (at a high pressure). Consequently, single-layer graphene is favored at low pressure due to the metal-passivated graphene edges whereas at high H2 pressure the H-terminated graphene edge favors the growth of bilayer or few-layer graphene. So, the hydrogen flow must be optimized to obtain the desired results due to the crucial role played by hydrogen in graphene CVD growth. The energy needed to decompose hydrocarbon gas can be supplied by heat (thermal CVD), plasma (plasma-assisted CVD), or light (laser-assisted CVD) [111]. The creation of plasma by the reacting gaseous precursors enables deposition at a lower temperature with respect to thermal CVD and requires lower deposition times. This is because plasma-enhanced CVD has additional high-density reactive gas atoms and radicals that facilitate the low-temperature and rapid synthesis of carbon nanostructures [113, 114]. Consequently, this method reduces energy consumption and prevents the formation of amorphous carbon or other types of unwanted products

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[115]. However, plasma can damage the growing material [116], so the equipment and process must be optimized to minimize this damage. Also, we note that CVD-grown graphene films are polycrystalline, being composed of numerous grains separated by grain boundaries, which are detrimental to graphene-based electronics. As such, efforts are being made to control graphene growth in a single crystal without any intrinsic defects. It is believed that, shortly, full control over the growth of singlecrystal graphene, including nucleation control and size and morphology engineering, will be achieved [117]. 2.3.1.2.6. Chemical Synthesis Graphene can also be chemically synthesized by the assembly of polycyclic aromatic hydrocarbons (PAHs) [118-121]. Two chemical approaches can be used to grow PAHs into larger graphenes [121]: 



A controlled chemical reaction under mild conditions in solution. To do so, first, a dendritic or hyper-branched precursor is synthesized and then ultimately transformed into the target structure by cyclodehydrogenation and planarization. Thermolysis, beginning with well-defined carbon-rich precursors, such as smaller PAHs, followed by reactions at a higher temperature to fuse or grow the PAHs into larger graphenes.

This method opens a new and broad field of organic chemistry research for synthesizing structures similar to graphene without its defects, controlling its size, and realizing properties similar to those of graphene. This could be a promising method for obtaining graphene, but the yield of those reactions as well as the cost of the process must be controlled. 2.3.1.2.7. Unzipping Carbon Nanotubes Carbon nanotubes (CNTs) are essentially rolled graphene sheets that enable graphene to be obtained by unzipping the CNTs. This unzipping could be achieved by oxidative treatment using sulfuric acid and potassium permanganate [122]. The opening mechanism is based on the oxidation of

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alkenes by permanganate in acid [122]. With these treatments, the obtained graphene is in oxidized form, so a reduction process is needed to recover the conductivity of the resulting graphene, as shown in Figure 8. Another unzipping method consists of the intercalation of an alkali metal such as lithium [123] or potassium [124] into multi-walled CNTs (MWCNTs) followed by exfoliation with acid treatment and abrupt heating.

Figure 8. a) Representation of the gradual unzipping of one wall of a carbon nanotube to form a nanoribbon. Oxygenated sites are not shown. b) The proposed chemical mechanism of nanotube unzipping.

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Figure 9. Schematic of the splitting process and SEM images of Si/SiO2 surface of graphene nanoribbons (GNRs) produced by potassium splitting. (a) Schematic of potassium intercalation between the nanotube walls and sequential longitudinal splitting of the walls followed by unraveling into a nanoribbon stack. The potassium atoms along the periphery of the ribbons are excluded for clarity. (b) Chemical schematic of the splitting processes in which ethanol is used to quench the aryl potassium edges. Only a single layer is shown for clarity, although the actual number of GNR layers correlates with the number of concentric tubes in the MWCNT.

2.3.2. Carbon Nanotubes 2.3.2.1. Structure and Properties Radushkevich and Lukyanovich [125] were the first scientists to observe and describe CNTs in 1952. In 1959, Hillert and Lange [126] reported CNTs with a concentric and bamboo texture and in 1976 Oberlin et al. [127] observed single- (or double-) walled CNTs. However, the discovery of CNTs in 1991 is attributed to Iijima, who described the synthesis of MWNTs using an arc-discharge evaporation method [64]. CNTs can be considered to be formed by the “rolling up” of a graphene layer. This “rolled up” layer can be produced in various ways, depending on the so-called chiral vector, C = na1 + ma2 (n ≥ m) [128]. Each (n, m) pair of values represents a possible structure. These structures are classified into three groups: the (n,0) structure is referred to as “zigzag,” the (n,n) structure is the “armchair,” and when n > m > 0, the structure is referred to as “chiral,” as shown in Figure 10. The chirality

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determines the electrical, optical, and mechanical properties of the CNTs [128]. CNTs can also be classified by the number of concentric walls as single-walled nanotubes (SWNTs) formed by only one rolled graphene sheet or MWNTs formed by few concentric tubes of graphene fitted one inside the other with interlayer spacing ranging from 0.34–0.39 nm [129]. The diameters range from 0.4–3 nm in SWNTs and from 2–25 nm in MWNTs, and the lengths extend up to several microns [129, 130]. However, MWCNTs and SWCNTs have similar properties [130].

Figure 10. The principle of CNT construction with a graphene sheet along the chiral vector–C. From [128].

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CNTs have interesting properties that make them optimal in several applications, including drug delivery, genetic engineering, biomedicine, artificial implants, as a diagnostic tool, as a catalyst, biosensors, field emitter arrays, and reinforced composites. Due to the sp2 bonds between individual carbon atoms, CNTs have a high Young's modulus, which is approximately five times higher than steel. The tensile strength or breaking strain of CNTs can be around 50 times higher than steel. These properties, coupled with the lightness of CNTs, give them great potential in applications such as aerospace. Moreover, another amazing property of CNTs is their elasticity. When subjected to a significant axial compressive force, they can bend, twist, and buckle without suffering damage to the nanotube, and then when the force ceases, the CNT returns to its original structure [130]. The electronic properties of CNTs are also very interesting and can be metallic or semiconducting, depending on their chirality. When 2n + m is a multiple of three [131], the CNT exhibits metallic behavior whereas nonmetallic/semiconducting behavior is exhibited in all other cases. Consequently, armchair CNTs are always metallic whereas zig-zag and chiral CNTs can be metallic or semiconducting, depending on the n,m vector. In theory, metallic nanotubes can carry an electrical current density of 4 × 109 A/cm2, which is three orders of magnitude higher than that of typical metal (e.g., Cu or Al) [132]. Moreover, CNTs have a high thermal conductivity of more than 3000 W/m K at room temperature, which is 10 times higher than that of copper [133, 134]. Also, pure CNTs are biocompatible, which, together with their other properties, make them appropriate for applications in biomedicine, including drug and vaccine delivery, biosensors, and the preparation of biomaterials such as reinforced and/or conductive polymer nanocomposites. Consequently an explosion of research has occurred in the study of their potential device applications [135]. All these amazing properties confer unique characteristics to CNTs that make them a very heavily researched material.

2.3.2.2. Synthesis There are three main techniques for synthesizing CNTs, which are summarized and compared in Figure 11 [130]: arc discharge, CVD, and

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laser ablation. Both the arc discharge and laser ablation methods are based on the condensation of a hot atomic carbon gas. However, these techniques involve high-energy consumption and require a lot of expensive instrumentation. Consequently, their implementation is not practical. Currently, these techniques have been replaced by low-temperature CVD methods (< 800°C) [130]. Today, CVD methodology is the only promising process for the production of CNTs on a reasonably large scale [136]. We discuss these three methods below.

Figure 11. CNT applications and synthesis methods (advantages and disadvantages of each). Images taken from [137].

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2.3.2.2.1. Arc-Discharge Method This method involves the application of a high electrical-potential difference between two electrodes, in which one is almost always graphite. A high-temperature discharge (above 1700ºC) is obtained between the two electrodes by applying a direct current of 50–100 A in an inert atmosphere (e.g., helium). The surface of the carbon electrodes is vaporized in the anode by the high-temperature discharge, and some of it condenses onto the cathode to form CNTs, which are mainly MWNTs, whereas the anode (positive electrode) is consumed. To synthesize SWNTs, the simultaneous vaporization of graphite and metal must be conducted in the anode. This complex anode consists of graphite and a metal or metal mixture. Many metals and metal mixtures have been studied [130] and Ni/Y and Co/Ni seem to be more effective, producing high SWNT yields (> 90%) [138]. Moreover, operation parameters must be optimized to improve the amount of CNTs synthesized. These factors influence the nucleation and growth of the CNTs, their inner and outer diameters, and the nanotube type (SWNTs, MWNTs). These operational parameters, including CVD in inert gas, the nature and composition of the catalyst used, the carbon vapor concentration, the temperature in the reactor, the addition of promoters, and the presence of hydrogen, have been studied in depth by many authors [130, 135, 138, 139]. 2.3.2.2.2. Laser Ablation The principles and mechanisms of laser ablation are similar to those of the arc-discharge method with the difference being that energy is provided by a laser beam. This laser beam is focused onto a metal–graphite composite target which is placed in a high-temperature furnace (1200ºC). The laser vaporizes the graphite and a flow of inert gas that is passed through the chamber carries the CNTs downstream to a collector surface (usually, a water-cooled copper collector) [139]. CNTs formed by this method are of higher quality than those produced by the arc-discharge method. However, the production quantity is very low, and this method is expensive with respect to both capital and energy. Many studies have shown that the quantity, quality, and structure of produced carbon material

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could be more or less controlled by controlling the atmosphere and its pressure, the nature of the metal catalysts and their composition, the temperature of the furnace, and the laser parameters [140]. As such, in recent years, the arc-discharge and laser vaporization methods are used when high-quality CNTs are required in small quantities. 2.3.2.2.3. Chemical Vapor Deposition This synthesis method is essentially the same as that for graphene synthesis, with the main difference being the catalyst. Whereas in the synthesis of graphene the catalyst consists of a film or foil of transition metals, in CNT synthesis it consists of round metal particles. As noted above, this method involves the catalytic decomposition of a hydrocarbon or a hydrocarbon mixture comprising, for example, methane, acetylene, or carbon monoxide at temperatures ranging from 500–1000ºC with the support of transition metal catalysts. The precipitation of carbon from the metal particle leads to the formation of tubular carbon solids in a sp2 structure. This method can produce both SWNTs and MWNTs by controlling the process variables. So, in this sense, the particle size of the catalysts is a significant factor. Rao et al. [141] demonstrated that particles with a diameter of around 1 nm mainly form SWNTs, whereas MWNTs are obtained at particle diameters ranging from 10–50 nm, with an increasing number of layers with increases in the particle diameter. Particles size larger than 50 nm are covered with amorphous graphitic sheets [141]. Consequently, the nanotube diameter can be controlled by varying the active particles size of the catalyst. On the other hand, the length of the tubes depends on the reaction time. In this method, unlike those we described previously, a catalyst is always needed to grow the CNTs, so a purification method to remove the catalyst is required. Alternatively, different synthesis configurations can be employed: a horizontal furnace in which the catalyst is placed in a ceramic or quartz boat, which is then put into a quartz tube; a vertical furnace whereby the catalyst is placed on the top of the furnace and the resultant filaments grow during flight and are then collected at the bottom of the chamber; or a fluidized bed reactor in which the catalyst is placed in the center of the

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furnace. The vertical configuration is typically used for the continuous mass production of CNTs. Different types of CVD methods have also been developed to improve the hydrocarbon decomposition. The first CVD method employed was thermal CVD, however this method has been recently replaced or enhanced by other techniques such as hot-filament (HF-CVD), plasmaenhanced (PE-CVD), microwave-plasma (MP-CVD), water- or oxygenassisted CVD, or radio-frequency CVD. These CVD types have been extensively reviewed by a number of authors [128, 139]. Overall, CVD is considered to be an economically viable process for the large scale and the production of relatively pure CNTs. Consequently, in recent years, the arc-discharge and laser vaporization methods are used only when high-quality CNTs are needed in small quantity. 2.3.2.2.4. Other Methods CNTs can also be successfully prepared by flame pyrolysis, solar techniques, hydrothermal synthesis, electrolysis, or even a bottom-up organic approach. In flame pyrolysis, a flame is created by the combustion of, generally, a hydrocarbon such as methane, ethylene, or acetylene to produce a gaseous mixture including carbon dioxide, carbon monoxide, water vapor, hydrogen, saturated and unsaturated hydrocarbons, and radicals. As such, the flame provides both the chemical species and the energy needed for the synthesis of the CNTs. To provide active sites for the CNT growth, metal catalysts are inserted into the flame either in the form of a substrate coating or as aerosol particles. With this method, both MWNTs and SWNTs can be synthesized and their structures depend on the nature of the catalyst, particle size, and carbon deposition rate [142]. Consequently, flames (a continuous-flow process) offer the potential to synthesize CNTs in large quantities at significantly lower cost than other methods currently available [143]. The solar method is a laser ablation variant in which solar light is used as in laser ablation to induce the vaporization of the graphite target. Hydrothermal synthesis is a new method that offers advantages with respect to the traditional methods such as lower treatment temperatures

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(160–180ºC vs. 500ºC in the best CVD process), easily obtained carbon sources, and no need to use dangerous gases such as H2. In a typical procedure, the initial carbon source solution, e.g., ethyl alcohol, NaOH, and polyethylene glycol, is transferred into a hermetic reactor and heated at 160–180ºC for 24 h [144]. Then the reactor is cooled to room temperature and the product is washed. As such, this method provides an easy way to obtain CNTs. Also, like graphene, CNTs can be chemically synthesized by controlling the chirality by utilizing hoop-shaped carbon macrocycles— small CNT fragments. For example, an armchair CNT can be synthesized by fusing new phenyl rings to 5-cycloparaphenylene (Figure 12a). Similarly, a zigzag CNT can be constructed, in principle, from 10cyclacene (Figure 12b). As a consequence, CNTs with a specific chirality will be synthesized utilizing a rational bottom-up approach [145].

Figure 12. Bottom-up, organic CNT synthesis approach using CNTs with discrete chirality [145].

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2.3.3. Carbon Nanofibers Carbon nanofibers (CNF) have a high specific area, flexibility, electrical conductivity, and strength due to their nanosized diameters that enable their use in the electrode materials of energy storage devices and as hybrid-type fillers in carbon-fiber-reinforced plastics and bone tissue scaffolds, as well as in electrical devices, electrode materials for batteries and supercapacitors, and as sensors. CNFs are produced by two main methods: catalytic thermal CVD and electrospinning followed by heat treatment. In the CVD method, several types of metals and alloys have been used to catalyze the growth of the CNFs. The main metals used are iron, cobalt, and nickel, due to their unique ability to break and form carbon–carbon bonds, but other metals such as vanadium, chromium, and molybdenum have also been considered. All these metals or alloys can dissolve carbon to form metal carbide and consequently induce the growth of CNFs. Generally, methane, carbon monoxide, synthesis gas (H2/CO), ethylene, and ethane in the temperature range 420–920°C are employed to produce carbon atoms. The growth mechanism [146, 147] has been confirmed to involve the deposition of hydrocarbons dissolved in the metal particles and precipitated onto the metal surface as graphitic carbon. As such, the shape and particle size of the metal catalyst used is fundamental to this process because it governs the CNF structure. In the electrospinning process, a viscoelastic polymer solution is exposed to an electric field, i.e., a high voltage is applied within a spring containing the solution and a collector. As the applied electrical potential reaches a critical value and the resulting electrical force on the droplet of the solution overcomes its surface tension and the viscoelastic force, a jet of polymer solution is ejected from the tip of the spring and electrospinning begins [148]. When the solvent evaporates, this jet solidifies and forms polymers nanofibers that are then collected by a collector. This collector can be a flat metallic plate, a mesh forming a random nonwoven mat, or a rotating round collector to obtain continuous and aligned fibers. Finally, polymer nanofibers are carbonized by heating the polymer to 1000°C in a specific environment. As such, these polymer

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solutions are rather limited, because the polymer must be converted to CNFs by heating as polyacrylonitrile (PAN), polyimide (PI), poly(vinyl alcohol) (PVA), poly(vinylidene fluoride) (PVDF) and pitch, although many other kinds of polymers have also been electrospun [149].

Figure 13. Schematic diagram of the electrospinning process, showing the syringe, high voltage source, and the collector plate [150].

Electrospinning is a relatively straightforward and low-cost strategy for producing continuous nanofibers from polymer solutions or melts and a non-required catalyst. Consequently, the purification process required by the CVD method can be avoided. Figure 13 shows the setup for the electrospinning process.

2.3.4. Nanodiamonds Nanodiamonds have the desirable properties of superior hardness and Young's modulus, biocompatibility, optical properties and fluorescence, high thermal conductivity and electrical resistivity, chemical stability, and resistance to harsh environments. These properties make them interesting for application in tribology and lubrication, energy storage, magnetic resonance imaging, nanocomposites, drug delivery, protein mimics, and

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tissue-scaffold and surgical implants. Figure 14 shows SEM images of nanodiamonds. The conversion from graphite to nanodiamond requires extremely high temperatures (> 1000ºC) and pressures (> 15 GPa). In the 1950s, Bovenkerk et al. [152] synthesized nanodiamonds using graphite dissolved in molten transition metals such as tantalum, ruthenium, iridium, iron, cobalt, and nickel. Carbon precipitates as a diamond at around 5–6 GPa and 1300–1700ºC. Nanodiamonds can also be produced using the carbon contained in high-energy explosives, which provide both a source of carbon and energy for the conversion or a mixture of carbon and high-energy explosives. The resultant detonation product is a mixture of diamond particles 4–5 nm in diameter with other carbon allotropes and impurities [153].

Figure 14. SEM images of CVD nanodiamonds. (a) Overview image area 8×6 μm2; (b) detailed pictures of typical well-faceted nano-diamonds [151].

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2.3.5. Carbon Nanospheres Carbon nanospheres (CNSs) are very attractive materials due to their high surface-to-volume ratio, the possibility of precisely controlling their particle size, surface area, pore size, chemical composition, and dispersity, and their greater pore accessibility and faster molecular diffusion/transfer. Moreover, most CNSs are formed by unclosed graphene layers in a spherical arrangement, which creates many open edges at their surface as the flakes must follow the curvature of the sphere [154, 155]. Consequently, these spheres have many surface reactive sites which give them a high chemical activity. Also, a wide range of structures with different degrees of porosity and graphitic characteristics can be obtained. All the above features make CNSs suitable candidates for catalyst supports [154, 155], electrochemical and energy storage applications [156-159], column packing materials [158], lubricating materials [160], and reinforced rubber additives [158], among others. Moreover, ultrafine CNSs, typically less than 200 nm, could be readily internalized into cells by intracellular endocytosis and thus be successfully extended to biomedical and pharmaceutical applications such as the delivery of drugs, genes, proteins, and imaging agents [161]. These spheres can be classified according to two criteria—their carbon layer arrangement [162]: radially, concentric, or randomly oriented; or their size: (a) Cn family and graphitic carbon onions, with diameters in the range 2–20 nm, (b) less graphitic carbon spheres with diameters in the range 50 nm–1 µm, and carbon beads, with diameters from one to several microns [163]. CNSs are spherical particles of carbon smaller than 100 nm. As such, some authors classify these carbon spheres as belonging to the nanoscale. These spheres have been synthesized by a range of different processes, which we describe below. 2.3.5.1. Synthesis In general, carbon spheres can be prepared using three main approaches: i) direct synthesis using methods such as CVD deposition, pyrolysis, and hydrothermal treatment; (ii) a template-assisted method to obtain mainly hollow carbon spheres such as nanocastings using silica

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spheres as hard templates or soft-templating strategies via organic–organic self-assembly, and iii) the synthesis of polymer spheres, followed by carbonization in an inert atmosphere to obtain carbon spheres [158]. We describe some of these methods below. 2.3.5.1.1. Chemical Vapor Deposition/Pyrolysis of Hydrocarbons As noted above, CNSs can be synthesized utilizing a catalytic process similar to those used to produce CNTs, graphene, or CNFs, which is the catalytic decomposition of a hydrocarbon at high temperature. A number of authors have synthesized CNSs by catalytic CVD (CCVD). Serp Ph. et al. [163] obtained well-dispersed CNSs ranging between 100 nm and 300 nm as a byproduct (around 500 mg per batch of 1 g) during vapor-grown carbon fiber experiments at 1100ºC in a reductive atmosphere from a CH4– H2 mixture in the presence of a metallic iron catalyst. In the same way, a mixed-valent oxide-catalytic carbonization process was found by Wang, Z. L. and Kang, Z. C. [164] to yield monodispersed carbon spheres at low cost. Also, these authors reportedly controlled the process with respect to temperature to produce either all carbon spheres at 1100°C or all pure carbon tubes at 950°C by the decomposition of CH4 using transition and/or rare earth metal oxides with mixed valences as catalysts [165]. Moreover, Miao, J.Y. et al. [166] prepared CNSs by CVD using Kaolin-supported transition metal catalysts and showed that they can increase the yields of the collected carbon spheres from 0.3 g to 0.7 g by increasing the temperature from 650°C to 950°C, but that this also increases the sphere size from 400 nm to 2000 nm.

Figure 15. Carbon nanospheres synthesized by PE-CVD by Qu L. et al. [167].

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However, CNSs with a size of approx. 30–60 nm have been synthesized in a vacuum PE-CVD system by Qu L. et al. [167] using a Si wafer without any catalyst. The authors flowed C2H2 gas (50–80 mTorr) through the furnace at 750ºC with on-line plasma (80 W) for 10 min and CNSs were spontaneously formed on the Si wafer (Figure 15). In the same way, Nieto-Marquez et al. [168, 169] performed CVD experiments to synthesize CNSs and reported that in the absence of a catalyst, CNSs similar to those obtained with a catalyst are produced, and as a consequence, the spheres are produced via a thermal rather than catalytic pathway. This fact was also observed by other authors during the thermal pyrolysis of various hydrocarbons at temperatures ranging from 600ºC to 1200ºC with or without a catalyst [170, 171]. So, based on the above, the main factor controlling the growth of CNSs is the reaction temperature, whereas the catalyst may play some role in assisting carbon growth and determining some of the lattice structure [169]. On the other hand, obtaining carbon spheres by CVD requires a purification step post-treatment to remove the catalyst, and this process is usually limited to the small scale. Large-scale production of pure carbon spheres, with diameters from 50 nm to 1 µm, has been achieved via the direct pyrolysis (as described above) of a wide range of hydrocarbons in the absence of a catalyst [172]. Moreover, nitrogen-doped carbon spheres can be obtained by the pyrolysis of nitrogenated hydrocarbons such as nitrobenzene or aniline, which is very attractive for many application [171]. Furthermore, Nieto-Márquez et al. [171] observed that the presence of nitrogen in the feed resulted in the enhanced curvature of the product due to a nitrogen-induced reduction in the energy barrier to form pentagons that buckle the graphitic layers and favor the formation of spheres. 2.3.5.1.2. Hydrothermal Treatment The hydrothermal method is one of the most studied methods for preparing carbon spheres due to its versatility and low cost as well as the cheap raw materials used. This method involves two steps—dewatering at low temperatures and carbonization at high temperatures. In the first step, carbohydrate decomposition, polycondensation, and polymerization for

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highly cross-linked and carbon-rich polymers occurs at low temperature (e.g., < 300ºC) and self-generated pressure (e.g., 1.0 MPa). The second step consists of the carbonization of the as-prepared organic spheres to obtain carbon spheres. This method was recently summarized by Zhang et al. [173]. Hard carbon with perfect spherical morphology was prepared for the first time by Wang et al. [174], who used a hydrothermal method. This method uses a stainless steel autoclave at 190ºC for 5 h that contains an aqueous sugar solution as the raw material, after which the obtained powder is carbonized in an argon atmosphere at 1000ºC. Scanning microscopy images of this sample reveal perfect spherical shapes and uniform particle size. Moreover, the authors observed that the diameter of the carbon spheres depended on the sugar concentration and hydrothermal time, i.e., the sphere diameter increased at higher sugar concentrations (0.25 µm vs. 5 µm at 0.15 mol/l and 1.5 mol/l, respectively) and longer treatment times (1.0 nm, 2.5 nm, and 5.0 nm at 1 h, 2 h, and 5 h, respectively) up to a certain concentration (3 mol/l), at which the solution becomes sufficiently dense and the size of the carbon spheres tends to be constant (5 µm). However, their surface areas are not very large (around 400 m2/g), so activation treatments are needed to improve their application in some areas. A similar conclusion was reached by Joula et al. [175], who controlled the size of carbon spheres by the concentration of the initial sucrose solution. By changing the solution concentration from 0.5 mol/l to 0.1 mol/l, the authors reduced the sizes of the carbon spheres from about 2500 nm to about 300 nm. The hydrothermal temperature is also a very important factor for controlling the size of carbon spheres. Falco et al. [176] showed that, using glucose as a raw material, higher temperatures (260ºC vs. 160ºC) lead to larger particles (685 nm vs. 474 nm) and a more homogeneous average size, which can be explained by the change in the water content upon increasing the temperature under self-generated pressures. Therefore, the solvent ability and reaction behavior are strongly affected over a narrow temperature range. Moreover, the authors observed that temperature also affects the carbon sphere yield. No solid residue can be recovered up to

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160ºC, and the maximum yield is achieved at 200ºC, after which the yield begins to gradually decline due to the fact that increased temperature favors gasification reactions and consequently the loss of carbon as a volatile compound. To obtain CNSs with a mean diameter of less than 200 nm requires a low concentration of the carbohydrate (sugar) solution, a low reaction temperature (~150°C), and a low reaction time. Nevertheless, the smaller are some of these parameters, the smaller is the yield of CNSs [177]. So, to obtain smaller spheres without decreasing their amount, additives have recently been used to better control the sphere sizes as well as their porosity. Pan et al. [178] synthesized monodispersed colloidal CNSs on a large scale with the assistance of polyoxometalates (POMs) under hydrothermal conditions. SEM images of samples prepared with and without the POMs reveal that these products not only act as a catalyst in promoting the glucose dehydration process, but also as a stabilizer to prevent the aggregation of CNSs (Figure 16). Moreover, the type of POMs used modified the diameters of the CNSs from 100 nm to 900 nm, due to the different acidic and oxidizing properties of POMs.

Figure 16. SEM images of CNSs prepared at 160°C, (a,b) with 0.5 M glucose but without POMs, (c) with 1 M glucose, 0.2 g H3PW12O40-xH2O, and (d) with 0.5 M glucose, 0.3 g H3PW12O40-xH2O.

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Figure 17. HRSEM images of the ordered mesoporous CNSs prepared using a lowconcentration hydrothermal method at 130°C: a) MCN-140 with a diameter of 140 nm; b) MCN-90 with a diameter of 90 nm; c) MCN-50 with a diameter of 50 nm, and d) MCN-20 with a diameter of 20 nm.

Surfactants or copolymers such as Pluronic F127 have also been employed as templates for controlling the size and morphology of CNSs. Fang et al. designed a low-concentration hydrothermal route for synthesizing mesoporous carbon nanoparticles with a spherical morphology and a tunable and uniform size. Using the hydrothermal method at 130ºC, the triblock copolymer Pluronic F127 was employed as a template and as a structure-direct and morphology control agent, with phenolic resol as a carbon source. The spherical diameters were tuned from 20 nm to 140 nm by simply varying the reagent concentration. Figure 17 shows SEM images of the obtained CNSs. 2.3.5.1.3. Sol–Gel Polymerization Sol–gel polycondensation of certain organic monomers such as resorcinol and formaldehyde is a promising method for obtaining CNSs in

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large amounts and with controllable porosity and size. The reaction between resorcinol and formaldehyde involves an addition reaction to form hydroxymethyl derivatives of resorcinol and further condensation of the hydroxymethyl derivatives to form methylene, as well as methylene-etherbridged compounds by the elimination of water, to yield a cross-linked polymerized resorcinol–formaldehyde resin network. This sol–gel polymerization of resorcinol and formaldehyde was performed for the first time by Pekala and since that time it has been extensively studied by a number of authors due to this method’s versatility, the well-developed and controlled micro- and mesoporosity and large surface area of the asprepared material, and consequently their great applicability in the fields of catalysis and adsorption. This preparation method involves three main stages: the first is the preparation of the sol mixture, its gelation, and the subsequent curing of the gel, for which the most important factors by which the properties of the organic gel are controlled are the concentrations of the catalyst and reactants (R and F) and the initial pH [179]. The second stage involves drying the wet gel, which is critical to avoid porosity collapse by the solvent removal, and the third stage is the carbonization of the dried gel. Using this method, organic gel microspheres can be formed by an inverse emulsion of sol mixtures that have adequate rheological performance. With this technique, microspheres of around 10 µm were synthesized by Zapata-Benabithe et al. using R and F as a carbon source and Span 80 as the surface active agent [180]. These authors also demonstrated that the rheological properties of resorcinol–formaldehyde sols at the very beginning of the emulsion polymerization process have a profound impact on the final shape of the microparticles obtained, as shown in Figure 18 [181]. CNSs can also be produced using this approach. Bailón-García et al. [182] synthesized carbon spheres with an average particle size of around 250 nm and with a high yield by the polymerization of resorcinol and formaldehyde using cesium carbonate as a catalyst without the need of a template as a structure-direct agent. To do so, the authors used a lowconcentration approach, i.e., they performed the polymerization reaction

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using a stirred batch reactor in aqueous media. The microparticles obtained are shown in Figure 19.

Figure 18. Final shape of the microparticles obtained.

Figure 19. Final shape of the microparticles obtained by Bailón-García et al. [182].

Figure 20. Carbon nanospheres obtained by left: silica template and right: electrospinning [189].

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Other authors have obtained CNSs using a modified Stöber method, which consists of the ammonia-promoted polymerization of resorcinol and formaldehyde in an ethanol–water solution, followed by thermal treatment in a nitrogen atmosphere. The particle size of the obtained colloidal products can be easily tuned from 900 nm to 150 nm by changing the ratio of alcohol to water, changing the amounts of ammonia and RF precursor, using alcohols with short alkyl chains, and introducing a triblock copolymer surfactant [183-186]. However, the synthesis of monodispersed nanospheres with diameters less than 200 nm remains a great challenge. To obtain a particle size of less than 200 nm, a silica template and the electrospinning technique together with RF polymerization can be used. Following this method, smaller hollow resorcinol–formaldehyde nanospheres with particle sizes ranging from 80 nm to 400 nm have been synthesized using silica as a template [187, 188]. Sharma et al. [189] prepared CNSs using sol–gel processing of organic and aqueous resorcinol–formaldehyde (RF) sols combined with an electrospraying technique. In this way, monodispersed CNSs of around 30.2 nm were successfully synthesized (Figure 20) by varying the process parameters such as the needle gage diameter, applied electric potential, and flow rate. In the light of the foregoing, the carbonization of phenol/formaldehyde resin has been recognized as the most effective method for synthesizing CNSs at large scales, due to the associated advantages and flexibility of the sol–gel method as well as its facile preparation, high thermal stability, and easy conversion to carbon materials [184, 185, 190].

2.4. Synthesis of Metallic Nanomaterials, Bimetallics, and Ceramics Before discussing the synthesis of these materials, we begin here by defining them. These materials are inorganic substances composed of one or more metallic elements and may contain some non-metallic elements [191, 192]. The metals have a crystalline structure in which the atoms are

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set in an orderly fashion. Some examples of the metallic elements include iron, copper, aluminum, nickel, and titanium [192]. These metallic materials may contain non-metallic elements such as carbon, nitrogen, and oxygen. The metals and alloys are usually divided into two categories: alloys and non-ferrous metals lacking iron or that contain a relatively small amount of iron [192]. The metallic materials are obtained from stable mineral species in natural conditions. Therefore, when exposed to environmental conditions, they intend to stabilize chemically and energetically to create oxides, and this process is called corrosion [193]. Other types of materials are ceramic, which are inorganic materials formed by chemically bonded metallic and non-metallic elements [194]. Ceramic materials can be crystalline, non-crystalline, or a mixture of both [191]. Most ceramic materials have excellent hardness and resistance to high temperatures but also tend to be fragile [194]. To highlight the advantages of ceramic materials for industrial application, they are light weight, have great resistance and hardness, good resistance to heat and wear, low friction, and isolating/shielding properties [194]. There are many ways to classify ceramic materials. One way is to define them based on their chemical compounds (for example, oxides, carbides, nitrides, sulfides, fluorides, etc.) [195]. Another way is according to their main functions. Ceramic materials are used in a wide range of technologies, including refractories, plugs, and dielectrics in capacitors, sensors, abrasives, and magnetic recording media. An important application of advanced ceramics in aircraft are the ceramic tiles of the space shuttle [192]. Ceramic materials also occur in nature as oxides or natural materials. The human body has an amazing ability to manufacture hydroxyapatite, a ceramic material found in bones and teeth [196]. Ceramic materials are also used as coatings. Glazed ceramic coatings are applied to glass objects and enamels are ceramic coatings applied to metal objects. Alumina and silicon ceramics are most commonly used [197]. Silica (SiO2), possibly the most widely used ceramic material [198], is the essential ingredient in glass and many other ceramic materials. Silica-based materials are used in

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thermal, refractory insulation abrasives as fiber-reinforced composites and laboratory glassware. In continuous long-fiber formations, silica is used in the manufacturing of optical communications fibers [199]. SiO2 has been synthesized in various precursors such as metal salts, and the most commonly used alkoxides include silicon tetrachloride (SiCl4) [200], tetramethoxysilane (TMOS) [201], methyltrimethoxysilane (MTMS) [202], methyltriethoxysilane (MTES) [203], tetraphenoxysilane (TPOS) [204], and tetraethoxysilane (TEOS) [205]. Applications include SiO2 glass and glass jewelry. Currently, investigations are underway to use SiO2 as an anti-corrosive coating [194]. Currently, there are a number of methods using the SiO2 matrix in film form, including the CVD technique [206] and its variations such as plasma-assisted CVD (PACVD) [207] and CVD at low pressure (LPCVD) [208]. Another method for obtaining SiO2 is pyrolytic decomposition [209], in which a film is applied by spraying a solution onto a hot surface, on which the compounds react to form a chemical compound. The precursors most commonly used for this SiO2 synthesis method are alkoxides such as TEOS and tetra-phenoxy silane (TPOS) [204]. To obtain SiO2 powders, the method most commonly used is a solid-state reaction using temperatures higher than 1000 °C [192]. Only the dispersions of SiO2 (silica, silicon dioxide) and certain polymers [210] have yielded the narrow size distribution required for forming high-quality colloids. Kolbe [211] was the first to produce spherical SiO2 particles through hydrolysis and the condensation of tetraethyl orthosilicate in a solution of water/alcohol, using ammonium hydroxide as the catalyst system. Some years later, Stöber et al. prepared monodispersed silica particles under controlled growing conditions in the micrometer scale. The resistance of ceramic materials depends on the size distribution of the defects and is unaffected by the movement of dislocations [192]. Ceramic materials are not always fragile. Using low speeds and hightemperature slow deformation, researchers have produced many ceramic materials with a very fine grain size that exhibit superplastic behavior [210].

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2.4.1. Synthesis of the Ceramic Materials Ceramic materials are melted at high temperatures and exhibit a brittle behavior in response to stress [194]. As a result, molding and thermomechanical processing, which is widely used for metals, alloys, and thermoplastics, cannot be applied when processing ceramic materials. However, inorganic glass at lower melting temperatures can be used, thanks to the formation of a eutectic in the float glass process [199]. Since merger, molding, and thermo-mechanical processing are not viable options for polycrystalline ceramic materials, ceramic materials are usually processed into desired shapes from ceramic powders. A “powder” is simply a collection of fine particles [212]. The manufacturing of a ceramic powder involves the synthesis of ceramic materials. Ceramic powder is prepared by crushing, grinding, removal of impurities, mixing with different dry powders, and spray drying to form soft agglomerates. Next, one of several techniques, such as compaction, pregnant molding, or extrusion molding, is used for draining, to convert the processed powder into the desired powder form, known as a green ceramic (one that has not yet undergone heat treatment) [213]. This green ceramic material is then consolidated using a high-temperature treatment known as sintering or burning in a controlled atmosphere to obtain a dense material [213]. The ceramic material is then subjected to further processing such as grinding, polishing, or machining, as required for the end application. In some cases, fixed terminals, electrodes are deposited or deposited in coatings [199]. Nanocrystalline ceramics are produced by the conventional powder metallurgy techniques described above. The difference is that the initial powder is less than 100 nm in size [214]. However nanocrystalline ceramic powders tend to bind to each other, either chemically or physically, to form larger particles called agglomerates or aggregates. Agglomerated powders, even if the particle size is controlled by a manifold pressure gage or is kept nearly level, can also be packaged as non-agglomerated powders. In a nonagglomerated powder after compaction, the available pore sizes range between 20–50% of the size of the nanocrystal. Due to this small pore size, the densification sintering step must be carried out quickly and at lower temperatures [192].

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2.4.2. Nanomaterials Summary Nanomaterials are a new class of materials (ceramic, metals, semiconductors, polymers or a combination thereof), in which at least one dimension is less than 100 nm [211]. These materials represent a transition between molecules and atoms and a solid mass (“bulk”). Nanoparticles have existed on the planet for centuries. Examples include carbon black particles and nanoparticles within bacteria. The early use of metal nanoparticles can be traced to the Egyptian culture in the year 4000. BC, who used PbS nanoparticles (5 nm) in hair dyes [23]. They also used gold nanoparticles as medicinal colloids to retain their youth and maintain good health [211]. Manipulation of synthesis conditions allows for the control of particle morphology and provides a means to tailor the material properties during the synthesis process [211]. Another key aspect of nanoparticle synthesis is stabilization to ensure that the particles maintain their size and shape over time. Due to their unique physical and chemical properties, nanoparticles are often described as artificial atoms [196, 215]. The synthesis processes allow for the control of structural parameters that dominate the formation of the nanoparticles, so that properties can be tailored according to their specific use. The synthesis of nanoparticles allows for their modular assembly to exploit their unique properties, which can lead to new applications in catalysis, electronics, photonics, magnetism, and chemical and biological sensing. As noted above, the terms “top-down” and “bottom-up” indicate the approaches used in the synthesis of nanoparticles [202, 211]. “Top-down” is the division of a solid mass into smaller portions. This approach can involve the volatilization of a solid followed by condensation of the volatilized material, chemical methods, and grinding or wear. The “bottom-up” category is the synthesis of nanoparticles through condensation of atoms or molecular entities in a gas phase or solution [196]. The latter nanoparticle synthesis approach is much more popular than the former. Nanoparticles can also be supported and they can be given specific properties by this support, in addition to stability [196, 216].

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The most representative “top-down” methods are as follows [202, 211]: 







CVD, which involves the breakdown of one or more volatile components inside a vacuum chamber (reactor) at or near the surface of a solid to result in the formation of a material as a thin layer or nanoparticles [217]. Ion implantation, which consists of material ions that can be implanted into a solid, thereby changing its physical and chemical properties. The implanted ion may be a different element and may cause structural changes in the implanted solid, since the crystal structure of the target may be damaged [196]. Ion implantation equipment consists of an ion source that produces ions of the desired item, an accelerator in which these ions are electrostatically accelerated to achieve a high energy, and a chamber in which the ions collide against the target. Each ion is usually an isolated atom, and thus the amount of implanted material in the object is the integral over time of the ion stream. This quantity is referred to as the dose [218]. The currents supplied are usually very small (microamperes), so the dose that can be implemented within a reasonable time period is also small. For these reasons, ion implantation is appropriate for applications for which the necessary chemical change is small. Typical ion energies are in the range of 10–500 keV. The energy of the ions in the ion species and the composition of the target determines the penetration depth of the ions in the solid [196]. Thermal evaporation consists of heating the deposition material to evaporation. This is performed in a vacuum chamber in which the vapor on a cold plate condenses, and at all times requires the precise control of the growing conditions to prevent changes in the morphology of the deposited layer [219]. Grinding of macroparticles to micrometric size using high efficiency mills. The resulting particles are then classified by physical means with respect to the nanoscale. Since continuous

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vigorous grinding of the starting materials can confer energy changes in the solids due to the accumulation of defects in the nonequilibrium situation, this may cause a decrease in the activation energy and could enable the solid to undergo chemical reactions in the solid state [220]. The mechanochemical activation of crystalline solids and alterations may also result in both textural and structural changes, which can be of great interest in the development of materials [221]. Mechanosynthesis by the reaction between metals and oxides have been studied in some systems to obtain nanostructured composite materials [211, 222]. As we can see from the above descriptions, several methods that use the topdown approach, except for milling, require complex instrumentation, which makes them expensive. Therefore, often the preferred methods are those utilizing the “bottom up” approach. There are several methods that use the “bottom-up” approach in the synthesis of nanoparticles, the most popular of which are chemical. Usually, these methods are initiated by reducing metal ions to metal atoms, followed by the controlled aggregation of these atoms. The chemical method is most suitable for producing uniform and small nanoparticles.  The preparation of gaseous clusters uses a high-power pulse to produce metallic atomic vapors that are hauled through an inert gas and then deposited on a single-crystal oxide or another substrate under laser ultra-high vacuum conditions [223]. The most representative of these methods are the following: a) Colloidal method Colloids are individual particles that have dimensions bigger than atomic dimensions but are small enough to exhibit Brownian motion. If particles are small enough to be colloids, then their irregular movement in suspension can be attributed to the collective bombing of a multitude of thermally excited molecules in a liquid suspension [224]. If they are big enough, then the dynamic suspended behavior as a function of time is governed by the forces of gravity and yield sedimentation behavior.

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Particle sizes in a colloidal solution ranges in the nanometer scale, so the colloidal method is an efficient way to produce nanoparticles [211, 225]. This method involves dissolving a salt or metal oxide precursor to prepare a reducer and a stabilizer or dispersion in a continuous phase (liquid in this case). The dispersion option can play a stabilizing role, a reducing role, or both. In principle, the average size, shape, and dispersion or morphology of nanoparticles can be regulated by changing the concentration of the reactants, the degrees of reduction and stabilization, and the nature of the dispersion medium. In the early 1950s, Turkevitch reported the first standard and reproducible method for preparing metal colloids (gold particles of 20 nm by reducing [AuCl4] with sodium citrate). He was also the first to propose a step-by-step formation of nanoclusters based on a growth mechanism and nucleation [226, 227]. b) Solvothermal synthesis Solvothermal synthesis is a group of techniques taking place in a closed container in which there is a metal precursor dissolved in a liquid. This liquid is heated above its boiling point and generates a pressure moderately above atmospheric [228]. Usually, the liquid used is water, and hence the name “hydrothermal synthesis.” However, with the passage of time, researchers have been using other liquids that require longer reaction times (compared to other chemical methods), such as hydrazine, organic solvents, and liquid ammonia, among others [229]. Hydrothermal synthesis has special characteristics that act upon or mineralize the solvent itself, so reagents that are difficult to dissolve in water pass into the solution. These syntheses are heterogeneous reactions in an aqueous medium generated above 100 °C and 1 bar. This technique achieves better dissolution of the components of a system and can react or dissolve species that are otherwise poorly soluble, including titanates, silica, and aluminosilicates [230]. Some agents, known as “mineralizers,” may be added to enhance in either direction the dissolution capacity of water. These agents may be acids, bases, complexing agents, or reducing or oxidizing agents. We also note that water at 600 °C in a liquid state (for which it is necessary to apply pressure to prevent a change to the vapor

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state) has a stronger than usual dissociation, thus making it behave as an acid or a rather strong base (amphoteric) that is capable of performing more aggressive acid–base attacks [231]. The application of nuclear species for a product in its own environment and to generate cavities is currently used as a template for the synthesis of nanosized species [230, 231]. c) Microwave irradiation The microwave irradiation technique is a “bottom-u” technique that lacks the ability to properly control the morphology of the nanoparticles, even if nanoparticles are generated with a very low dispersion. Microwaves can heat any material that contains electrical loads using a high-frequency electric field [232]. By heating their molecular components, polar solvents are rotated by this action and lose energy in the resulting collisions. When the ions and electrons in conducting and semiconducting samples form an electric current, the samples are heated and energy is lost due to the electrical resistance of the material [231]. Recently colloidal nanoparticles of Pd, Rt, Ag, and Pt have been prepared by heating precursor metal salts dissolved in solutions of ethylene glycol. This is one of the preferred methods due to its favorable rate and effectiveness in the synthesis of nanoscale materials [195]. Also, liquid samples heated by microwaves generate a more homogeneous environment for the nucleation and growth of particles due to the decrease in the temperature fluctuations in the reaction medium [195, 233]. d) Sol–gel method Sol–gel is a wet-chemical process used in the manufacture of nanomaterials, most commonly metal oxides [234]. The starting point for this synthesis method is a chemical solution or sol which acts as a precursor to an integrated network of either discrete particles or network polymers, in which the precursors undergo several hydrolysis and polycondensation reactions to subsequently form a colloidal dispersion. This colloidal dispersion can create a gel by slow polymerization. The

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precursors commonly used in this method are metal chlorides and metal alkoxides. Generally, alkoxides break down very easily in wet environments and for this reason, hydrolysis in the formation of gels uses alcohol as a solvent, which is common to various immiscible fluids [225, 231]. A gel may form when the concentration of the species increases and is defined as an infinite macromolecular network that is swollen by a solvent. The solvent is trapped in the network of particles and the polymer network prevents the liquid from separating, while the liquid prevents the solid from collapsing into a compact mass. A partially dewatered gel produces a solid residual called a xerogel. This material is completely dehydrated and then heat treated with gas flow to yield the nanostructured material [225, 231] The sol–gel method has been used in recent years to prepare a wide variety of nanostructured materials. This method is of great interest because it involves low-temperature processes, as well as high purity and homogeneity, due to its form of preparation in multi-component systems [225]. Nanoparticle dispersions are thermodynamically metastable because of their very high surface area, which positively contributes to the free enthalpy of the system. In addition, the highly dispersed nanoparticles are stabilized only kinetically and cannot be generated above a certain limit, for which so-called “soft chemistry” methods are preferred. A method widely used in stabilization involves depositing nanoparticles onto a support, usually a metal oxide, to prevent sintering, recrystallization, and aggregation. This type of supported nanostructured material is handy in the areas of catalysis, optics, and medicine, among others. Classical methods for depositing metal-oxide nanoparticles are impregnation, the deposit– precipitation method, ionic adsorption, and photochemical deposits and colloids [225]. e) Use of dendrimers A dendrimer is a three-dimensional macromolecule in a tree-like construction. Dendrimers are polymers, but their difference arises in the probabilistic distribution of molecules that constitute linear polymers,

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whereas in dendrimers the precise structure of the chemical bonds between atoms may be accurately described [235].

Figure 21. Dendrimer and its elemental unit: the dendron [235].

In the synthesis of nanoparticles, also using micelles, emulsions, and dendrimers as nanoreactors allows for the synthesis of defined particle shapes and sizes, which alters the nature of the dendrimers. Dendrimers are highly branched molecules comprising a central core, intermediate

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repeating units, and terminal functional groups [236]. Dendrimers represent a new type of macromolecule having a high molecular weight and low viscosity, in addition to a molecular shape and a three-dimensional spatial structure. Their sizes vary from 2–15 nm and they are natural nanoreactors. The end groups of the dendrimers can be modified with hydroxy groups, carboxyl, and hydroxy carboxyls, among others. In addition, dendrimers with several terminal functional groups have proved suitable for synthesizing monometallic and bimetallic nanoparticles [231] (Figure 21). f) Photochemistry and radiochemistry reduction The generation of highly active and strongly reducing electrons, radicals, and excited species is associated with the synthesis of metal nanoparticles by modifying the chemical system using high energy [231]. Photochemical reduction (photolysis) and radiation–chemical (radiolysis) processes differ in the level of energy used. Radiolysis is characterized by energies between 103–104 eV, whereas photolysis uses energies below 60 eV. These methods produce nanoparticles of high purity due to the absence of the formation of impurities when using reducing chemicals, considering that photochemical reduction in solution is often used to sinter the particles of noble metals. In addition, with photochemical and radiochemical reduction it is possible to produce nanoparticles under solid-state and low-temperature conditions [231].

CONCLUSION The synthesis of nanomaterials is a complex process that includes mechanical and physical methods that modify nanoparticle properties such as size and surface area. The methodologies used in the synthesis of nanoparticles are characterized as either bottom-up or top-down. In topdown methods, the particle size decreases with increasing reactivity, which leads to coalescence, necking, and subsequent reaction of the particles. Bottom-up methodologies include methods such as solvothermal synthesis,

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microwave-assisted, ultrasound-assisted, and precipitation and coprecipitation, all of which build nanoparticles from individual atoms. Carbon nanomaterials like fullerenes, carbon nanotubes, graphene, nanodiamonds, and carbon nanofibers can be synthesized using methods such as mechanical exfoliation, chemical exfoliation, electrochemical exfoliation, epitaxial growth, and chemical vapor deposition, especially with graphene. Nanodiamonds use high temperatures and pressures to achieve good conversion of graphite nanodiamonds. The synthesis of nanospheres requires more complex methods using more materials, including chemical vapor deposition/pyrolysis of hydrocarbons, hydrothermal treatment, and sol–gel polymerization. Metallic materials are obtained from corrosion, whereby the exposure of mineral species to environmental conditions tends to chemically stabilize them and to energetically create oxides. Ceramic materials are inorganic materials formed by metallic and non-metallic elements that are chemically bonded, which can be crystalline, non-crystalline, or a mixture of both. These are synthesized by solvothermal and sol–gel methods and microwave irradiation, among others.

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[216] Wachs, I. E., Characterization of catalytic materials: Momentum Press, 2010. [217] Park, J. H. a. T. S. S., Chemical vapor deposition vol. 2: ASM International, 2001. [218] Ryssel, H. a. I. R., Ion implantation, 1986. [219] Dai, Z. R., Pan, Zheng W., and Wang, Zhong L., “Novel nanostructures of functional oxides synthesized by thermal evaporation,” Advanced Functional Materials, vol. 13, pp. 9-24, January 2003. [220] Hadjiiski, A., Dimova, Roumiana., Denkov, Nikolai D., Ivanov, Ivan B., and Borwankar, Rajendra., “Film trapping technique: precise method for three-phase contact angle determination of solid and fluid particles of micrometer size,” Langmuir, vol. 12, pp. 6665–6675, December 25 1996. [221] Boldyrev, V. V., “Mechanochemistry and mechanical activation of solids,” Solid State Ionics, vol. 63-65, pp. 537-543, September 1993. [222] Takacs, L., “Metal-metal oxide systems for nanocomposite formation by reaction milling,” Nanostructured Materials, vol. 2, pp. 241-249, May 1993. [223] Lee, S. K. a. D. Y. B., “Observation of Vibronic Emission Spectrum of the Jet-Cooled 2,6-Difluorobenzyl Radical,” The Journal of Physical Chemistry A, vol. 104, pp. 5219–5221, May 10 2000. [224] Shen, H., Wang, Hongzhe., Yuan, Hang., Ma, Lan., and Li, Lin S., “Size-, shape-, and assembly-controlled synthesis of Cu 2− x Se nanocrystals via a non-injection phosphine-free colloidal method,” Cryst Eng Comm, vol. 14, pp. 555-560 2012. [225] de Jong, K. P., Synthesis of solid catalysts: John Wiley & Sons, 2009. [226] Turkevich, J., Stevenson, Peter C., and Hillier, James., “A study of the nucleation and growth processes in the synthesis of colloidal gold,” Discussions of the Faraday Society, vol. 11, pp. 55-75, 1951. [227] Turkevich, J. a. G. K., “Palladium: preparation and catalytic properties of particles of uniform size,” Science, vol. 169, pp. 873879, August 28 1979.

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In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 4

WETTABILITY ALTERATION IN SANDSTONE CORES USING NANOFLUIDS BASED ON SILICA GEL Stefanía Betancur1,3,*, Camilo A. Franco1,2 and Farid B. Cortés1,2,† 1

Grupo de Investigación en Fenómenos de Superficie Michael Polanyi, Facultad de Minas, Universidad Nacional de Colombia–Sede Medellín, Medellín, Colombia 2 Grupo de Yacimientos de Hidrocarburos, Facultad de Minas, Universidad Nacional de Colombia–Sede Medellín, Medellín, Colombia 3 Grupo de Investigación en Materiales de Carbón, Departamento de Química Inorgánica, Facultad de Ciencias, Universidad de Granada, Granada, Spain

* †

Corresponding Author Email: [email protected]. Email: [email protected].

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ABSTRACT In an oil reservoir, depending on specific interactions between rock, oil, and brine, the wettability of the system can change from a water-wet to a strongly oil-wet condition. This situation can reduce the mobility of fluids in the reservoir and, therefore, affect oil recovery. In this way, the oil industry has used chemical agents, such as surfactants to change the wettability of reservoir rock and thus release the oil from the rock. Recently, nanofluids, due to their chemical characteristics, have been considered as potential modifiers of wettability. The aim of this investigation is to evaluate the effectiveness of silica-based nanofluid in altering the sandstones core wettability with an induced oil-wet wettability and compare its performance with that of a commercial surfactant. For this study, silica nanoparticles were synthesized by using the sol-gel method. Nanofluids with different concentrations between 100 mg L-1 and 10,000 mg L-1 were prepared by dispersing silica nanoparticles in an aqueous solution. Similarly, fluids with commercial surfactants were prepared with concentrations between 100 mg L-1 and 10,000 mg L-1 by dispersion in an aqueous solution. The effect of the nanofluids and the commercial surfactants on altering the wettability was evaluated by the contact angle and the imbibition test. The results illustrated the nanofluid provided better performance in altering the wettability of the rock over that of the commercial surfactant. The best performance was achieved when a concentration of 100 mg L-1 was used. It was shown that the nanofluids could change the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Additionally, a core-displacement test was performed by injecting a nanofluid into the sand pack by dispersing silica nanoparticles in an aqueous solution. A reduction in the residual oil saturation, an increment of oil mobility, and a displacement to the right of the oil relative-permeability curve were obtained, which indicated that the nanofluid restored the rock wettability.

Keywords: wettability, nanofluid, nanoparticle, surfactant

INTRODUCTION Wettability is one of the most important factors in the processes of oil recovery and reservoir productivity. Wettability is the tendency of the reservoir rock surface to contact a particular fluid preferentially [1]. A water-wet rock will preferentially contact water and an oil-wet reservoir

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will preferentially contact oil [2]. Wettability is affected by the minerals present in the pores and their distribution. Clean sandstone or quartz is extremely water-wet, sandstone reservoir rock is commonly intermediatewet, while carbonates are oil-wet [2]. Regardless of its origin and mineralogical composition, it is considered most reservoir rocks have a mixed state of wettability, i.e., they do not have complete wettability conditions to water or oil [3]. However, the wettability of reservoir rock can be altered by different mechanisms. The oil-drilling fluid can alter reservoir rock wettability from a water-wet to an oil-wet condition or a mixed state of wettability. Wettability can also be altered by the presence of asphaltenes in crude, for example, when the reservoir attains the onset precipitation point [4] or gas injection processes [5]. Processes involving ionic interactions and surface precipitation have been identified as the main mechanisms contributing to altered wettability of mineral surfaces exposed to precipitation of asphaltenes in the presence of water [4]. Surfactants have been used in oil reservoirs to reduce the interfacial tension between the water and the oil, to alter the wettability of the rock and therefore, to recover the residual oil of the reservoir [6, 7]. The surfactants are amphiphilic substances, i.e., they possess a polar-apolar duality [8, 9] and can interact with the surface rock, which increases operating costs. Recently, there has been widespread use of nanoparticles as an alternative technology to solve various problems in the oil industry. The high ratio of surface area/volume, the nanometer size, and the highadsorptive capacity of nanoparticles [3] has made possible the application of these materials in the optimization of drilling fluids [10-12], inhibition of the formation damage by asphaltenes [13, 14], fines migration control [15, 16], upgrading of crude oil [17-19], among others. In this case, the application of nanoparticles in the oil industry to solve problems related to the alteration of the wettability of the reservoir rock is of great interest. In this study, a comparison regarding altering the wettability between a commercial surfactant and aqueous nanofluid based on SiO2 nanoparticles, inducing damage caused by asphaltene precipitation in the reservoir rock is presented. Methods for determining wettability were contact angle and spontaneous imbibition. From this, it is expected to significantly alter the

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wettability of the rock so that it can achieve high productivity of the reservoir.

1. WETTABILITY ALTERATION OF POROUS MEDIUM Wettability is a term used to describe the relative adhesion of two fluids to a solid surface [20]. In porous media, wettability is defined as “the tendency of one fluid to spread on or adhere to the solid surface in the presence of other immiscible fluid, either oil or water” [21]. When the rock surface has no preference for either fluid, the system is said to exhibit neutral wettability and presents intermediate wettability when it is equally wet by both fluids (50%/50% wettability) [20]. Also, since the internal surface of the rock is composed of many minerals with different surface chemistry and adsorptive behavior, other types of wettability are presented. With fractional wettability, also called heterogeneous wettability, a portion of the rock is strongly water-wet, while the rest is strongly oil-wet [22, 23]. Fractional wettability recognizes that most rocks have very different surface chemistry properties, which leads to variations in wettability in the internal surface of the pores [20]. It is worth mentioning that fractional wettability is conceptually different from intermediate wettability, which assumes all portions of the rock surface have equal preference to being wetted by water or oil [21]. Mixed wettability was defined by Salathiel [24] as a special type of fractional wettability in which the oil-wet surfaces form continuous paths through the larger pores. In the mixed wettability, the smaller pores are occupied by water and are water-wet, while the larger pores of the rock are oil-wet and form a continuous filament of oil throughout the core [20, 21]. This type of wettability is probably the most common reservoir condition [24]. The original reservoir wettability can be altered by different mechanisms that involve the system crude/oil/brine/rock. These mechanisms include the polar interactions in the absence of water between the crude oil and the solid surface, surface precipitation that depends mainly on crude/oil/solvent properties regarding their asphaltenes,

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acid/base interactions that control surface charge at the oil/water and solid/water interfaces and finally ion binding or specific interactions between the charged sites and the valence ions [25]. In the adsorption of polar compounds, one of the materials that adsorbs most strongly from crude oil is the asphaltene fraction [26]. Asphaltenes are defined as the fraction of petroleum, bitumen, or refinery residue which is insoluble in low molecular weight paraffin, such as n-pentane or n-heptane and is soluble in light aromatic hydrocarbons, such as toluene, pyridine, or benzene [27]. These types of hydrocarbons have high molecular weight and contain compounds, such as sulfides, nitrogen, and oxygen, and metals including vanadium, iron, and nickel [28]. The polar end adsorbs on the rock surface, exposing the hydrocarbon end and therefore leading the surface to be more oil-wet [20]. Asphaltenes can adsorb on surface rocks as colloidal aggregates or as individual molecules through carboxylic and phenolic weak acidic groups [29, 30]. According to Al-Maamari et al. [4], the polar components in crude oils can adsorb due to ionic interactions that include the ionization of acids and bases at the oil/water and solid/water interfaces and the surface precipitation interactions. The chemical components of brine can also alter the wettability of the reservoir rock. The pH and salinity of brine can affect the surface charge on the rock surface and fluid interfaces, which facilitates the adsorption of surfactants onto the surface rock [21]. Polar functional groups present on both the rock surface and the crude oil can behave as Brønsted-Lowry acids or bases [31], i.e., the polar functional group can donate a proton (becoming negatively-charged) or receive a proton (leading to positive charges). In this way, a cationic surfactant can be attracted to a negativelycharged surface, while an anionic surfactant can be attracted by a positively-charged surface solid. For example, the SiO2 surface is negatively-charged, near neutral pH and tends to adsorb organic acids, while calcite at this pH is positively-charged and tends to adsorb organic bases [21]. Additionally, for example, in SiO2/oil/brine systems, multivalent metal cations present in the brine can reduce the solubility of

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the surfactants and promote the adsorption phenomena of these compounds on the rock surface and change the rock to be more oil-wet [21, 32]. Many different methods have been used to measure the wettability of a system. These methods include quantitative techniques, such as contact angles, imbibition and forced displacement (Amott), and the United States Bureau of Mines (USBM) wettability method. On the other hand, there are the qualitative methods that include microscope examination, flotation, glass slide method, relative permeability curves, capillary pressures curves, capillarimetric method, and nuclear magnetic resonance [22]. In practice, only the contact angle measurement, the Amott method, and the USBM [33] methods have been used. The contact angle is used for determining if a crude oil can alter the wettability and to indicate the effects of temperature, pressure, and brine composition on wettability [22]. The contact angle (  ) is defined by the angle between the fluid-solid interface. When the oil and water are together in contact with the rock surface, the contact angle is defined by the angle measured through the water. If  < 90°, the reservoir rock is water-wet, when  > 90°, it is oilwet, and when   90°, the reservoir rock a neutral-wet system [2]. The Amott method [34] combines imbibition and forced displacement to measure the average wettability of a core. Both the reservoir core and the fluids can be used in the test [22]. This method defines two different indexes: The Amott index to water ( IW ) and the Amott index to oil ( I O ). The Amott wettability index is calculated following Eq. (1) and it reflects the ease with which the wetting fluid can displace the non-wetting fluid [2]. An Amott index to water of 1 indicates that the core is water-wet, whereas 0 indicates that an extremely oil-wet system exists [35].

WI Amott  IW  IO

(1)

The USBM method [33] compares the work necessary for one fluid to displace another. This work is proportional to the area under the capillary pressure curve ( AW , AO ) [36]. The USBM wettability index WIUSBM is calculated according to Eq. (2). For the extremely water-wet system,

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WIUSBM is very large and positive; for a neutral-wet condition, WIUSBM is around 0, whereas for an extremely oil-wet condition, WIUSBM is very large and negative [2].

A  WIUSBM  Log  W   AO 

(2)

The main advantage of the USBM method over the Amott method is its sensitivity near neutral wettability. However, the USBM index can only classify the core as either water-wet (wettability index is greater than 0), oil-wet (wettability index is less than 0), or neutral-wet (wettability index is equal to 0).

2. NANOPARTICLES FOR WETTABILITY ALTERATION OF POROUS MEDIUM One of the most striking areas of scientific and technological development is nanotechnology. Nanotechnology is the ability to control and restructure matter at the atomic and molecular levels in the range of 1–100 nm, with the aim of creating materials, devices, and systems with new properties and functions [37]. Nanoparticles are particles with an average size in the range of 1 to 100 nm [38] and represent a transition between atoms, molecules, and materials with volumetric solid dimensions. Because of their nanometric size, nanoparticles have properties that may differ from a material with the dimensions of solid volumetric, atom molecules, such as surface area and free surface energy, which affect its properties, such as melt temperature and chemical reactivity. For example, it has been reported that the melting temperature of Pt nanoparticles is reduced from 1,773 °C in a volumetric solid to 600 °C in nanoparticles with an average size of 8 nm [39]. This behavior shows that while materials with the dimensions of volumetric solids have physical

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properties independent of their size, the size of the nanoparticles determines their physicochemical properties. Nanoparticles can be modified by adjusting their properties, such as average particle size, surface area, optical properties, catalytic capacity, among others [40]. The definition of rock wettability is the tendency of a fluid to adhere to the rock surface in the presence of another immiscible fluid. Wettability is one to the main factors that controls the distribution and flow of fluids in the pores of a reservoir [41]. According to Sun et al. [42], “wettability is a key factor in governing oil recovery by affecting capillary pressure, fluids saturation and relative permeability.” Consequently, some researchers proposed various methods to avoid altering the wettability of reservoir rock. The use of various types of surfactants has been the focus of several investigations. Seethepalli et al. [43] investigated the use of basic anionic surfactants to change the wettability of different carbonate rocks, such as limestone, marble, dolomite, and calcite. These authors found that the surfactant used modified the condition of wettability of the calcite rock from oil-wet to water, or intermediate-wet. The other types of carbonates studied showed similar results. Furthermore, Salehi et al. [44], used surfactants with different densities to alter the wettability of naturallyfractured reservoirs. According to the authors, the spontaneous imbibition process is more efficient if low concentrations of surfactant are added to the water injection process in naturally-fractured reservoirs. When electrostatic interactions exist between the charged head groups of the surfactant molecules and the adsorbed crude oil components on the rock surface, ion-pair interactions are the mechanisms responsible for the wettability alteration. While in the absence of an electrostatic interaction, surfactant adsorption, governed by hydrophobic interactions between the tail fraction of surfactant molecules and the adsorbed crude oil components on the rock surface, is the mechanism responsible for wettability alteration. The authors conclude that the surfactants with higher density on the head groups were more effective to change the rock wettability. However, the use of surfactants to alter the rock wettability is often expensive [45] due to their adsorption onto rock surfaces [6, 9, 46]. Recently, the use of nanoparticles as an innovative and alternative

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treatment for altering the wettability of the reservoir rock has been extended. Because of this, nanoparticles and smart fluids (nanofluids) are presented as an alternative to alter the wettability of the reservoir rock and to increase the productivity of the reservoir. Because of their nanometer size (diameter between 1 and 100 nm), nanoparticles have a high ratio of surface area/volume and can flow through pores of very small sizes. Additionally, the high-adsorptive capacity of the nanoparticles may contribute to the wettability alteration system [3]. Some studies were performed to investigate the effects of nanoparticle concentration on the wettability alteration. Giraldo et al. [3] evaluated the effectiveness of alumina-based nanofluids to alter the wettability of sandstone rocks. Nanofluids have five different concentrations ranging from 10 mg L-1 to 10,000 mg L-1 and were prepared by dispersing alumina nanoparticles in a commercial surfactant. Methods for determining wettability included the contact angle and spontaneous imbibition. These authors found that the nanofluids significantly changed the wettability of sandstone cores from oil-wet to strongly water-wet condition. Furthermore, they found that the surfactant was more effective when the nanoparticles are added at low concentrations (equal or less than 500 mg L-1). Li et al. [47] performed the Amott test to measure the wettability index IW . The nanofluids, based on the SiO2 nanoparticles, changed from an oil-wet core to a neutral-wet core, and the experiments showed that IW was independent of the nanoparticles concentration. The presence of crude oil decreased the capacity of the nanoparticles for wettability alteration. Others authors such as Roustaei et al. [48] evaluated the impact of the SiO2 nanoparticles on the wettability of carbonate systems and the effect on the nanoparticles concentration for determining the optimum concentration of nanofluid for injection into the core samples. The SiO2 nanoparticles changed wettability from the strongly oil-wet to strongly water-wet condition. Wettability alteration by adsorption of the nanoparticles on the rock surface was a fast process, at least one hour. Mohebbifar et al. [49] studied the ability of the nano-biomaterials to alter the wettability of shale rock. Three types of biomaterials, including a biosurfactant, a bioemulsifier, and a biopolymer,

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and two types of nanoparticles, including SiO2 and TiO2, were used as injection fluids. The presence of a layer of nano-biomaterial on the rock surface changed the wettability from oil-wet conditions to neutral or waterwet conditions. Al-Anssari et al. [50] evaluated the effect of the nanoparticles concentration, time, and reversibility of the nanoparticles adsorption for altering the rock wettability. The authors found that the nanofluids achieved a change in the wettability of the calcite from oil-wet condition to the strongly water-wet condition. The wettability change occurred after one hour. The adsorption of the nanoparticles on the rock surface was partially reversible, which was measured by washing the surface with acetone and deionized water. Other authors evaluated the effect of the nanoparticle type on alteration of the rock wettability. Hendraningrat et al. [51] evaluated two metal oxide nanoparticles that included aluminum (Al2O3) and titanium (TiO2) and compared them with SiO2 nanoparticles. The results indicated that the TiO2 nanoparticles changed the quartz plate to be more strongly water-wet. Karimi et al. [52] evaluated the effect of ZrO2-based nanofluids on the wettability alteration of a carbonate reservoir rock. The nanofluids composed of ZrO2 nanoparticles and the mixtures of nonionic surfactants changed the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. The authors indicated that the wettability change by adsorption of the ZrO2 nanoparticles on the rock surface is a slow process, requiring at least two days. The knowledge these properties and characteristics of the nanoparticles has made possible the application of these materials in diverse areas ranging from medicine [53, 54] and electronics [55-57] to the sports area [58, 59]. In this case, it is of interest to apply nanoparticles in the oil industry to solve problems related to the alteration of the wettability of reservoir rock. This study presents a comparison between a commercial surfactant and an aqueous nanofluid based on SiO2 nanoparticles for altering rock wettability. From this, it is expected to significantly alter the wettability of the rock so that a high productivity of the reservoir can be obtained.

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3. MATERIALS AND METHODS 3.1. Materials The material used for the wettability determination tests were SiO2 nanoparticles. For the synthesis, were used tetraethyl orthosilicate “TEOS” (>99%, Sigma-Aldrich, USA), ethanol (99.9%, Panreac, Spain), and ammonium hydroxide “NH4OH” (30%, J. T. Baker, USA). The oil used to induce damage to the rock, and the displacement test was an extra-heavy oil with 6.7 API gravity, a viscosity of 695,410 cP at 25 °C and asphaltene content of about 16%. Solvents like toluene (99.5%, Merck GaG, Germany) and n-heptane (99%, Sigma-Aldrich, United States) were used to prepare solutions with heavy oil for formation damage by precipitation/deposition of asphaltene in the rocks. The brine was prepared using 2% KCl (≥99%, Sigma-Aldrich, United States). The commercial surfactant used is a nonionic polysorbate 80, commonly named “Tween 80” (Sigma-Aldrich, St Louis, MO).

3.2. Methods 3.1.1. Synthesis of Silica (SiO2) Nanoparticles The synthesis of the SiO2 nanoparticles was performed based on the sol-gel method [60, 61] following a basic method. The sol-gel method is defined as the preparation of ceramic materials from the preparation of a sol, the gelation of the same and the removal of the solvent. The SiO 2 nanoparticles are synthesized through the formation of a 3-D interconnected network by simultaneous hydrolysis and polycondensation of an organometallic precursor, in this case, TEOS. For the synthesis process, TEOS, ethanol and 30% NH4OH were used. Subsequently, the solution was vigorously and continuously stirred for one hour at 25 °C. Finally; the sample was dried at 120 °C for 24 h. The molar ratio of TEOS: H2O: NH4OH that was used for the synthesis was 1: 1.1: 0.2 [13].

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3.1.2. Nanoparticles Characterization Samples were characterized by Field Emission Scanning Electron Microscopy (FESEM) and dynamic light scattering (DLS) for determining the particle size of the synthetized nanoparticles. The Brunauer-EmmetTeller method was used to determine the surface area (SBET) of the nanoparticles. A scanning electron microscope (JSM-6701F, JEOL, Japan) was used to determine the average particle size. With the aim to confirm this size, DLS [62] measurements were also performed using a Micromeritics Nanoplus-3 (Norcross, ATL) at room temperature using a 0.9-mL thick glass cell. The sample was dispersed in ethanol at a concentration of 0.5 mg L-1 and sonicated for 4 h. Finally, an aliquot of the solution was taken for analysis. The average particle diameter was obtained from the Stokes-Einstein according to Eq. (3):

dp 

K BT , 3 Da

(3)

where K B is the Boltzmann constant (1.38  10−23 m2  kg  s−2  K−1),

T (K) is the temperature,  is the viscosity (cP), and Da is the diffusion coefficient of the nanoparticles (m2  s−1).

3.1.3. Tests for Determining the Wettability In the preparation of rock samples, Ottawa sand clean was used in a 30-50 mess sieves. Also, a cylindrical container and cement industry was required. After the preparation and drying of the rock, sample damage was induced by precipitation/asphaltene deposition in the rock. For this, rock samples with ethanol and water were washed and dried at 120 °C for 2 h. Then, the rocks were immersed in a solution of crude/n-heptane (70/30) under stirring at 300 rpm for 18 h. This immersion was conducted to induce the formation damage by the asphaltenes on the rock. After this time, samples were washed with n-heptane and water and dried at 80 °C for 2 h.

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To emulate the soak treatment conditions in a real reservoir rock, a nanofluid with SiO2 nanoparticles and KCl 2% was prepared. The soak time was 48 h at 40 °C. The samples were dried at 40 °C for 24 h. The contact angle method and spontaneous imbibition tests were performed to determine the wettability of the rocks, and are described in the following sections. Contact angle tests: The contact angle test seeks to establish whether a fluid presents the oil-wet or water-wet condition quantitatively. In this case, it seeks to determine whether a drop of water or oil has a preference for the rock under investigation. This test is performed on the virgin rock, on an oil-wet rock and on the rocks treated with the nanofluid to establish the effect of this fluid on the rock wettability. Initially, three drops of water are placed in different areas of the rock surface. If the contact angle forming the water drop with the rock surface is less than 90°, the rock presents the water-wet condition; if it is equal to 90°, then it has intermediate wettability (it can be oil-wet or water-wet). In contrast, if the contact angle is greater than 90°, the rock is said to prefer oil (the oil-wet condition). Similarly, three drops of oil are placed in different areas of the surface of the rock. If the contact angle forming the oil drop with the rock surface is less than 90°, it is said that the rock presents the oil-wet condition. If it is equal to 90°, then it presents intermediate wettability, and if the angle of contact is greater than 90°, then the rock has a preference for water (the water-wet condition). The volume of the droplet is controlled and injected with a 5-μL syringe. To determine the contact angle, a photograph is taken using a digital camera placed at a distance of 5 mm from the sample [63]. The images obtained can be processed using LayOut software (Trimble Inc., Sunnyvale, CA). The contact angles are determined by selecting a baseline on the rock surface and adjusting the profile of the drop with a circumference or ellipse. Spontaneous imbibition: The method of spontaneous imbibition consists of placing a rock saturated with a fluid in the presence of another fluid and observing how much fluid is displaced by the sample by the

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effect of imbibition of the fluid that is on the outside of the sample. For the spontaneous imbibition test, the dry cores are placed inside a glass with water while hanging under an electronic balance. Once the core begins to imbibe the water, the accumulated weight is recorded as a function of time. The imbibition test ends once the weight recorded remains constant (equilibrium time). The relationship between the weight of imbibed water at a given time ( mw ) and the weight of imbibed water at equilibrium time ( mwT ) is plotted as a function of time for each evaluated core [64].

3.1.4. Design of the Experiments For the planning of these experiments, a Simplex-Centroid Mixtures Design (SCMD) was performed. The SCMD seeks to model the response variable mathematically and is evaluated using the components of the mixture with their respective proportions and searched for the proper fraction of each component to optimize the process [65]. Typically, a SCMD studies the relationship between the proportions of the different variables and the responses. In this case, the variables analyzed included the amount of water, the amount of nanoparticles, and the amount of surfactant, as shown in Figure 1. Initially, ternary high concentrations for the surfactant and nanoparticles with the maximum concentration 10,000 mg L-1, according to data reported by several authors [66-69] are considered. Similarly, low concentrations of surfactant and nanoparticles were considered for the design of the experiments, since some studies report that the nanofluid significantly changes the wettability of the rock under these conditions [3]. The fractions of each component are determined using the Eq (4):



q i 1

X i  X1  X 2  ...  X q  1, X i

0,

(4)

where X i and q are the proportions of each component and the number of components in the mixture, respectively. In the present study, q  3 where

X 1 represents the water fraction, X 2 represents the surfactant fraction, and

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X 3 represents the fraction of the nanoparticles. As mentioned above, the amount of surfactant and nanoparticles was restricted to 10,000 mg L-1 in the design. Accordingly, the limits for each compound are given by:

99%  Water  100%

(5)

0%  Surfactant  1%

(6)

0%  Nanoparticles  1%

(7)

Figure 1. Design of the experiments with mixtures of water, surfactant, and nanoparticles.

3.1.5. Displacement Tests The experimental setup of the displacement test consists mainly of a core holder, fluid injection cylinders, a positive displacement pump, a furnace, pressure meters, and manifolds. It should be noted that the core is adapted with two inputs to allow the simultaneous injection of two different fluids. The displacement tests were performed to evaluate the effectiveness of a nanofluid for the alteration of wettability of a porous medium.

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For the wettability test, the following working conditions were defined: temperature of 93 °C, pore pressure of 2,000 psi, and a pressure overload of 3,800 psi. To perform the displacement tests, the following procedure was evaluated: 1) construct the base curves, 2) generate and evaluate the damage induced by the precipitation/deposition of the asphaltenes (change in wettability), and 3) inject the nanofluid based on the SiO2 nanoparticles and evaluate its effectiveness for the alteration of wettability. Initially, 10 porous volumes (PV) of water were injected to measure the absolute permeability. Then, the crude oil was injected until the residual water saturation (Swr) was reached and the effective permeability to the base oil was measured. To complete step 1, 20 PV of water were injected to construct the base relative permeability curves. The base oil recovery curve (Np) was also constructed. To generate the precipitation of the asphaltenes and change in wettability, the porous medium was again saturated with oil, and then 0.5 PV of n-heptane (in the injection direction) was injected and allowed to soak for 12 h. After soaking, 10 PV of oil was injected, in a production sense, to measure the effective oil permeability after the damage. Then, 20 PV of water was injected to construct the relative permeability curves and the oil recovery curve after the damage. For the latter step, the porous medium was again saturated with oil, and 0.5 PV of nanofluid was injected in the injection direction and allowed to soak for 12 h. Oil was then injected to measure the effective oil permeability after the treatment, and finally, 20 PV of water was injected to construct the relative permeability curves and the oil recovery curve after the treatment. The properties of the sand packs are presented in Table 1. Table 1. Porous medium characteristics for the alteration of wettability tests Length (cm) Diameter (cm) Porous volume (cm3) Porosity (%)

11.39 3.81 18.21 14.03

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4. RESULTS 4.1. Synthesis and Characterization of the Nanoparticles The FESEM image obtained for the synthesized SiO2 nanoparticles is presented in Figure 2. From these results, a size of about 11 nm nanoparticles was obtained. Similarly, the surface area (SBET) for the SiO2 nanoparticles of 210.08 m2 g-1 was obtained.

Figure 2. FESEM micrography of the SiO2 nanoparticles.

4.2. Spontaneous Imbibition Method To evaluate the effect of each component of the experiments, spontaneous imbibition curves were performed to evaluate the change of wettability. These components include the nanoparticles, the surfactant, and water. The “y” axis indicates the dimensionless weight acquired by the rock during imbibition and the “x” axis is the time for the rock to increase its determined weight. In this work, the nanoparticles are labeled as “N,” the surfactant as “S,” and the nanoparticles/surfactant systems as “N-S.” The concentration that follows the nomenclature mentioned corresponds to the concentration of treatment in the mixture. For example, in the case of the “N 100 mg L-1” system, the mixture is composed of 100 mg L-1 of

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nanoparticles and the remainder is water. Likewise, for the “N-S 100 mg L1 ” system, the concentrations of the treatments in the mixture are 100 mg L-1 of nanoparticles and 100 mg L-1 of surfactant and the remainder is water. The spontaneous imbibition curves for samples treated with the SiO2 nanoparticles, for the virgin rock (without formation damage by asphaltenes) and damaged rock (formation damage by asphaltenes was induced in the rock) are presented in Figure 3. It is observed that there is a higher change of wettability toward the strongly water-wet condition for the rock treated with a nanoparticle concentration of 100 mg L-1. This behavior can be due to the nanoparticles interacting with the rock surface through electrostatic interactions. For the pure SiO2 nanoparticles, the point of zero charge corresponded to a pH of 2 [70], and for the commercial SiO2 nanoparticles, the pH value was lower than 3.2 [71]. It suggests that at a pH of 7, the SiO2 nanoparticles are charged negatively, giving rise to electrostatic interactions with the cations of the components of the crude oil adsorbed on the rock surface. In this way, the nanoparticles can form a layer on the rock surface and change the rock wettability to the more water-wet system, or even restore wettability. On the other hand, as observed in Figure 3, the rock treated with 10,000 mg L-1 of nanoparticles presents the lowest water-wet condition among the treated systems. This behavior shows that it is not always true that more nanoparticles produce a better effect regarding the rock wettability. Likewise, the slowest imbibition process occurred for the damaged rock. The spontaneous imbibition curves for samples treated only with a commercial surfactant are presented in Figure 4. In this case, the sample with 100 mg L-1 of surfactant presented the highest water-wet system. The mechanism responsible for the wettability alteration can be the electrostatic interactions between the hydrophilic head of the surfactant molecules and the adsorbed crude oil on the rock surface. Polyethers presented in the hydrophilic head of the “Tween 80” surfactant molecule can interact selectively with cations of crude oil adsorbed on the rock surface, which changes the rock wettability. These results are in agreement with those reported by Salehi et al. [44], who indicate that when electrostatic

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171

Mw/Mwt

interactions exist between the surfactant molecules and the crude oil adsorbed on the rock surface, an ion-pair formation is the mechanism for wettability alteration of the porous medium. On the other hand, similar to the case regarding treatment with the nanoparticles, the rock with 10,000 mg L-1 of surfactant displayed a lower water-wet condition than the systems with lower surfactant concentrations. From Figure 4, the curve for 100% water is shown. This sample does not have any treatment and therefore is less water-wet than the rocks treated with surfactants. 1.2 1 0.8 0.6 0.4 0.2 0

Virgin Rock N 100 mg/L N 500 mg/L N 1000 mg/L

N 5000 mg/L 0

10

20 30 Time (min)

40

50

N 10000 mg/L Water 100%

Mw/Mwt

Figure 3. Spontaneous imbibition curves for the rocks treated with the SiO2-based nanofluid.

1.2 1 0.8 0.6 0.4 0.2 0

Virgin Rock S 100 mg/L S 500 mg/L S 1000 mg/L S 5000 mg/L 0

10

20

30

40

50

S 10000 mg/L Water 100%

Time (min) Figure 4. Spontaneous imbibition curves for the rocks treated with a commercial surfactant.

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Virgin Rock

Mw/Mwt

1

N-S 100 mg/L

0.8

N-S 500 mg/L

0.6

N-S 1000 mg/L

0.4

N-S 5000 mg/L

0.2 0

N-S 3333 mg/L

0

10

20 30 Time (min)

40

50

N-S 1666 mg/L

Figure 5. Spontaneous imbibition curves for the rocks treated with the SiO 2-based nanofluid and commercial surfactant.

The spontaneous imbibition curves with the SiO2 nanoparticles and commercial surfactant rocks are presented in Figure 5. The rock treated with 100 mg L-1 of SiO2 nanoparticles and 100 mg L-1 of surfactant (N-S 100 mg L-1) presents better performance and a higher water-wet condition than the other samples. In this case, low and high concentrations of the treatment were also evaluated, and it was evidenced that the low concentrations of treatment showed a greater change of wettability to the water. From these results, it can be observed that there is no synergistic effect between the SiO2 nanoparticles and the commercial surfactant, which indicates that the nanoparticles are an alternative material to change the wettability of reservoir rocks.

4.3. Contact Angle Method The contact angle of the water and oil droplets was compared with the rock surface and is presented in Figure 6. The system with a nanoparticles concentration of 100 mg L-1 was selected for its good performance in the spontaneous imbibition tests. It is noted that for a damaged rock, the angle between the oil drop and the rock surface is less than 90°, which suggests

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that the rock is oil-wet. Likewise, for the treated rock with a nanoparticle concentration of 100 mg L-1, the angle of the oil drop is greater than 90°, which indicates that the nanofluid based on the SiO2 nanoparticles could alter the rock wettability to a more water-wet condition.

Figure 6. Comparison of the contact angles of the water drops and oil drops for damaged rocks and treated rocks with a nanoparticle concentration of 100 mg L-1.

4.4. Displacement Test Displacement tests were performed to determine the effects of the synthesized nanoparticles in the alteration of wettability under reservoir conditions. The nanoparticles concentration used for the preparation of the aqueous nanofluid was 500 mg L-1. The absolute permeability of the packed sand was 658 mD, while the effective oil permeability was 407 mD. The relative permeability curves for the restored and treated rock are

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presented in Figure 7. As observed, the curve of relative oil permeability is higher for the treated system than the restored system. This behavior occurs because of the damage induced by the n-heptane injection in the absence of the nanoparticles. Additionally, the increase observed in the Kro curve for the treated system can be due to the nanoparticles adhering to the rock surface, forming a layer which changes the rock wettability to the more water-wet condition. The shifts in the crossover point of the Sw values in the relative permeability curves is lower for the restored system than the treated system, which corroborates the fact that the nanofluid based on the SiO2 nanoparticles changed from an oil-wet system to a water-wet system. These results confirm that the nanofluids can alter the porous media wettability.

Figure 7. Relative permeability curves for the restored and treated systems.

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90 80

Oil Recovery (%)

70 60 50 40

Treated System

30

Restored System

20 10

0 0

2

4

6 PVI

8

10

12

Figure 8. Oil recovery curves for the restored and treated systems.

Oil recovery curves for the restored and treated system are presented in Figure 8 where the oil recovery in the restored system was 66% and that in the treated system was approximately 77%, which corroborates that the nanofluid based on the SiO2 nanoparticles can be an alternative chemical method to alter the porous media wettability and to increase the oil recovery factor.

CONCLUSION Nanoparticles with a considerable surface area suitable for the preparation and evaluation of nanofluids for altering the wettability of reservoir rock were synthesized. Spontaneous imbibition curves and contact angle tests provided evidence of the nanoparticles ability for altering and restoring the wettability of a previously damaged rock. Thus, the optimum concentration of the nanoparticles for this purpose was 100 mg L-1. Likewise, it is

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evidenced that the electrostatic interactions were the mechanisms responsible for wettability alteration, both for the rock-nanoparticle system and for the rock-surfactant system. The displacement test confirms the ability of the nanoparticles to change the rock wettability under reservoir conditions. A higher relative permeability to oil was obtained for that treated with the nanofluid system than that obtained for the restored system. Also, the use of a nanofluid based on SiO2 could increase the oil recovery by 11%. It should be noted that the SiO2 nanoparticles synthesized did not exhibit any modification or doping, which highlights the good performance of the nanoparticles remained unchanged.

ACKNOWLEDGMENTS The authors acknowledge the Universidad Nacional de Colombia for logistical and financial support. This work was conducted under the initiative of the SINERGIAS network of exploration and production of Ecopetrol and its subsidiaries: Formation Damage. The project was supported by the Vice President of Innovation and Technology of Ecopetrol through Instituto Colombiano de Petróleo (ICP) and carried out by Grupo de Investigación en Fenómenos de Superficie “Michael Polanyi” and Grupo de Investigación de Yacimientos de Hidrocarburos–Universidad Nacional de Colombia Sede Medellín through agreement 04 0f 2013.

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In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 5

SYNERGY OF SIO2 NANOPARTICLEPOLYMER IN ENHANCED OIL RECOVERY PROCESS TO AVOID FORMATION DAMAGE CAUSED BY RETENTION IN POROUS MEDIA AND IMPROVE RESISTANCE TO DEGRADATIVE EFFECTS Lady J. Giraldo1, Sebastian Llanos1, Camilo A. Franco1,2,* and Farid B. Cortes1,2, † 1

Grupo de Investigacion en Fenómenos de Superficie Michael Polanyi, Facultad de Minas, Universidad Nacional de Colombia–Sede Medellin, Medellin, Colombia

* †

Corresponding Author Email: [email protected]. Email: [email protected].

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Grupo de Yacimientos de Hidrocarburos, Facultad de Minas, Universidad Nacional de Colombia–Sede Medellin, Medellin, Colombia

ABSTRACT As an enhanced oil recovery technique, the polymer injection process has been widely used in recent years to improve sweeping efficiency in the hydrocarbon extraction process. However, the application of this technique has severe limitations, one of which is its adverse generation of formation damage processes in the reservoir by pore throat plugging or retention on porous media. Also, the various degradation processes to which the polymer is subjected due to reservoir conditions also leads to severe formation damage and operational problems. The primary objective of this work is to develop a suitable nanofluid for strengthening this enhanced recovery technique by reducing the possible adverse effects associated with formation damage and by generating a synergistic effect favoring the polymer’s integrity, based on the interaction of SiO 2 nanoparticles with hydrolyzed polyacrylamide (HPAM). This nanofluid was evaluated under different scenarios, in adsorptive processes, aggregate sizes, and adsorption and retention in porous media, as well as its rheological behavior concerning temperature (thermal stability). Also characterized the sample of the nanoparticles and HPAM using thermogravimetric analysis (TGA), Fourier-transform infrared spectroscopy (FTIR), and dynamic light scattering (DLS). It is conducted a batch-type adsorption process to maintain a fixed polymer concentration while varying the dosage of nanoparticles. The adsorption results show that the obtained isotherms exhibited Type-III behavior. Also, it is used UV-Vis spectrophotometry to measure the adsorption in porous media via batch mode. Then the adsorption isotherms were correlated with a solid-liquid equilibrium (SLE) model, obtaining a good fit with an root-mean-square error (RSME) of less than 10%. Similarly, the rheological behavior was fitting to the Herschel-Bulkley model with an RSME of less than 1%. The rheological tests were performed at 25ºC and 70ºC and found non-Newtonian behavior in all the SiO2–HPAM mixtures tested. The thermal stability of polymeric solutions was evaluated in the absence and presence of nanoparticles under oxidative atmospheres at 70°C for 14 days. The results show significant decreases in aggregate sizes by the addition of nanoparticles to the system, which decreases the probability of plugging the pores. Also was observed a

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lower degree of degradation in the presence of nanoparticles, which can be explained by the adsorptive function of HPAM onto SiO2.

Keywords: polymer, adsorption, Nanoparticles, retention, size aggregate, enhanced oil recovery (EOR)

1. INTRODUCTION The rapid development of society in recent years has spurred the global energy demand, whereas one of the main energy resources, i.e., hydrocarbons (fossil fuels), has recently experienced the lowest rates of discoveries of new deposits. This situation means new strategies must be developed and implemented. The oil-and-gas industry, in particular, has been concerned with the search for economically viable alternatives for increasing oil recovery rates from existing oil fields without generating adverse effects [1]. Typically, first and secondary recovery methods increase production rates by between 15% and 30% of the original oil-in-place (OOIP) reservoirs, depending on the petrophysical properties of the porous media or the fluid type. The use of improved recovery methods can increase these values up to 60% [2]. These methods are classified as either thermal or non-thermal [3, 4]. In thermal processes, a heat source is used to reduce the viscosity of heavy oil (HO) and extra heavy oil (EHO) to improve their mobility in the reservoir, thereby increasing their recovery rates [5, 6]. Non-thermal processes are based on miscible displacement and chemical invasion processes, which improve sweeping conditions in reservoirs [7, 8]. Of the various non-thermal processes, polymer injection is one of the most common enhanced oil recovery (EOR) processes used by industry to increase the sweeping efficiency in porous media. This technique is based on increasing the viscosity of the water injected by the addition of

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polymers, which improves the vertical and sand scavenging efficiency of the oil [9-11] and improves oil mobility, which leads to up to a 60% increase in the amount of oil recovered in comparison with traditional water-injection techniques [12]. However, this method has limitations due to the petrophysical characteristics of the reservoir, which often challenge its effectiveness or, conversely, may generate adverse effects on the reservoir. Possible adverse effects include pore throat blockage due to the large aggregation size of the polymer [9, 13] and the adsorptive processes of the polymer on the surface of the porous media decreasing the permeability effectiveness of sweeping or in some cases changes in the wettability of the medium. This adsorption process can also lead to higher economic expenditures [9]. Moreover, the degradative effects of the polymeric compounds due to the associated thermal, chemical, biological, and/or mechanical processes directly affect this technique’s efficiency and even bring about the above-mentioned negative effects [10, 12]. As such, there is a need for new strategies that circumvent these adverse effects and significantly improve upon the current method, and one good option may be the use of nanotechnology. Nanoparticle and nanofluid technologies offer exceptional advantages relating to size, surface area, and interaction forces that enable their application in reservoir conditions without the risk of additional formation damage (37-39). Studies published in the literature report that various methodologies involving the inclusion of nanoparticles in the polymeric system can yield significant effects regarding viscosity, interfacial tension, and the percentage of recovery oil in displacement tests (40, 41, 42, 48a, 46). As yet, there are no reports regarding the possible effects of aggregate size formation, adsorption on rock, or the possible inhibition of the polymer degradation process. In this chapter, it was investigated the synergistic effect of the inclusion of SiO2 nanoparticles in polymeric systems to prevent formation damage processes that occur due to the blockage of throat pores and adsorption on porous media and to inhibit degradation processes that could lead to additional formation damage.

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2. FORMATION DAMAGE IN POLYMER FLOODING Formation damage refers to any process that causes a reduction in the inherent natural productivity of an oil- or gas-producing formation [14]. This issue can occur at any time during the life of a well, including completion, production, stimulation, kill, or workover operations. Formation damage is caused by various mechanisms, primarily including mechanical, chemical, biological and thermal mechanisms that can be further divided into discrete sub-mechanisms. These interactions can significantly affect the productivity of an oil-and-gas reservoir and increase its associated costs and operations [15]. The main objective in adding polymer compounds to displacement fluids is to viscosify the aqueous phase to provide mobility control, which improves the displacement process and the oil–water mobility ratio, which leads to improved areal and vertical sweep efficiencies. One problem associated with large-scale polymer applications in the field is the potential decrease in injectivity caused by formation damage by the polymer solution. This occurs because there can be a significant interaction between the polymer molecules transported in the flow and the porous media. One result of this interaction can be the retention of the polymer by the porous medium, which leads to the formation of a bank of injection fluid wholly or partially denuded of polymers. As explained by Sorbie, this bank formation will have a lower viscosity than the initially injected polymer solution, which leads to a reduction in the polymer flooding efficiency of the EOR process [9]. On the other hand, the retention of the polymer on the porous medium can also cause significant reductions in the permeability of the rock, which directly increases oil recovery. This is why the retention of the polymer is considered to be a key factor in determining the feasibility of a polymer flooding project. The retention process refers to the various mechanisms by which the polymer component can be separated from the entire aqueous phase, and refers to the whole process rather than each mechanism. The retention mechanism involves adsorption on the porous medium, mechanical

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entrapment, and hydrodynamic retention [16, 17]. Mechanical entrapment is similar to filtration, in which large polymer molecules are forced to pass through very small pores. Much like filtration, there can be blockage of the pores, although this will not necessarily occur throughout the reservoir but depends on the petrophysical conditions of each zone. This entrapment process affects larger polymer molecules, based on the average size distribution of the porous medium, and inevitably leads to an accumulation of material close to the injection well. This disadvantages this injection process and considerably alters the penetration profile of the formation than would otherwise be expected. The potential blocking of pores is unacceptable, so the use of a polymer solution that may lead to such conditions must be discarded in any polymer flooding project [9]. Adsorption can be defined as the interaction between polymer molecules and the porous medium that leads to the polymer being adsorbed [18]. This interaction causes the polymer molecule to be bound to the surface of the solid mainly by physical adsorption through interaction forces such as van der Waals and hydrogen bonding. The polymer occupies the surface adsorption sites, so greater surface areas are available at higher adsorption levels. Adsorption is the only mechanism that removes a polymer from the bulk solution, thereby changing the concentration of the remaining solution. On the other hand, mechanical entrapment and hydrodynamic retention are similar, occurring only during flow through porous media. These mechanisms are related to the size of the polymer molecule aggregates when they become lodged in narrow flow channels [9, 16, 19]. The mechanisms of retention have been studied by several authors who have sought to quantify individual mechanisms [16, 20-22]. Gogarty [22] and Smith [21] evaluated the effective size of HPAM polymer molecules, identifying sizes between 0.4 and 2 μm, and obtaining larger sizes in distilled water than in brine. Willhite and Dominguez [16] presented pore size distribution data taken from a mercury porosimeter and noted that 14% of the pore volume is associated with a volume inaccessible to polymer molecules with an effective size of about 1 μm.

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Apart from taking into account the formation damage due to different retention mechanisms associated with the injectivity conditions in the reservoir and the formulation of the polymer solution, it is also important to consider the different degradative processes that polymer compounds can suffer in certain conditions, specifically in reservoirs. This degradation refers to any process that breaks the molecular structure of polymer macromolecules, which primarily occurs due to thermal, chemical, mechanical, and biological effects [23-28]. The adverse effects of degradation mainly include the loss of properties of the polymer system, such as viscosity, due to destabilization in the polymer structure, including the favoring of retention processes, such as higher adsorption in the porous medium and/ or plugging of the throat pores [9]. In polymer flooding in oil recovery operations, it is critical that the polymer solution be stable with no tendency to form separate phases in the reservoir for the given reservoir conditions, i.e., they must not rapidly degrade. Also, to minimize the possibility of generating any formation damage that might affect the efficiency of the process, the hydrodynamic size of the polymer molecules must not exceed the pore throat size associated with the porous medium. Hence, new strategies are needed to prevent formation damage and significantly improve the EOR method. By taking advantage of the properties offered by nanoparticles, a strategy for improving the EOR technique and increasing the productivity of reservoirs is presented.

3. NANOPARTICLES IN POLYMER FLOODING The current challenge to the industry is how to enhance available resources to obtain greater productivity while maintaining a cost-effective operation. Nanotechnology has emerged as an important tool for solving these problems, which uses nanoparticles (particles smaller than 100 nm) and combines the extremely high surface area and high adsorptive capacity of nanofluids to yield exceptional properties for application to reservoir conditions without the risk of additional formation damage [29-31].

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At present, many authors report the nanoparticle-polymer system to have a variety of inclusion options, primarily including mixing the nanoparticles with the polymer [32-34], or grafting, functionalizing, or chemically attaching the polymer to the nanoparticle surfaces [35, 36]. Although mixing has been the method most commonly assessed, some authors have studied the effect of nanoparticles inclusion. For example, Zhu et al. [37] and Yousefvand and Jafari et al. [38] studied the improvement in the rheological behavior of a polymer/water fluid by the addition of nanoparticles in laboratory conditions, and their results showed the resultant suspensions to have a nanofluid-like behavior that increased the viscosity of the system. Maurya et al. [33] studied the improvement of the rheological behavior of nanoparticle/water/polymer suspensions, in which the viscosifying effect attributed mainly to nanoparticle crosslinking properties is highlighted. The authors also showed how silica nanoparticles can alter the wettability of the porous medium A strongly water-wettable condition can be induced by injection with nanoparticles. Kennedy et al. [39] demonstrated this hypothesis with silica nanoparticles in combination with xantham gum and other polymers, showing that the addition of nanoparticles can enhance viscosity and elasticity. Lui et al. [34] performed a more complex synthesis of core-shell nanoparticles composed of a silica core with a polymer shell, by which they obtained reductions in interfacial tension and improved viscosity. On the other hand, Cheraghian [40] investigated the role of silica nanoparticles in the adsorption of a polymer on the solid surfaces of carbonates and sandstones, showing that lithology, brine concentration, and polymer viscosity are critical parameters influencing the adsorption behavior at a rock interface. These authors found the adsorption of nanopolymers (polymer solutions containing silica nanoparticles) to be higher in carbonates than in sandstones, which can be attributed to the various porosities and cracks in stones. It can be noted that in the above studies, the authors had mainly evaluated the effects associated with the addition of nanoparticles to polymer solutions through rheological studies, the reduction of the interfacial tension (IFT) [41], and coreflooding tests. As such, they lack

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foundational explanations regarding the interaction between the polymer and the nanoparticles. In this chapter, it is investigated the interaction between the polymer and nanoparticles in the system and the system properties, including the adsorptive processes of the polymer on silica and their effect on rheological behavior, retention in porous media, sizes of the aggregates formed, and thermal stability. The main objective in this research was to improve the polymer flooding technique by the use of nanotechnology, specifically by taking advantage of the characteristics of SiO2 nanoparticles (size, surface area, and low reactivity with the porous medium) without the use of complex in-situ synthesis processes reported by some authors [34, 42]. By adding nanoparticles to an aqueous water/polymer system, the efficiency of the EOR process is improved by increasing the viscosity of the water to obtain higher scanning efficiency and thus higher recovery factors, reducing the risk of formation damage by retention in the porous media by plugging of pores or adsorption. Also, by the inclusion of silica nanoparticles, higher sustainability of the rheological properties of the injection fluid for more extended periods of time are obtained, especially the viscosity, and thereby minimize potential system alterations by parameters that are not controllable or are natural to the reservoir.

3. MATERIALS AND METHODS 3.1. Materials The SiO2 nanoparticles employed in this study were purchased from Sigma-Aldrich (St. Louis, MO). The polymer sample used was a commercial sample of partially hydrolyzed polyacrylamide and deionized water were used for to prepare the polymer solution. The molar mass and the hydrolysis degree of the polymer sample were 2 to 6 million Daltons and 30%, respectively. The SiO2 nanoparticles using N2 physisorption at 77 K with an Autosorb-1 instrument from Quantachrome (Florida, USA) and X-ray diffraction (XRD, X Pert PRO MPD, PANalytical, Almelo, the

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Netherlands) to determine the surface area (SBET) and particle size (dp), respectively. The estimated Brunnauer, Emmett and Teller (BET) surface area is 389 m2/g, and the mean particle size of the silica nanoparticles is 7 nm (mean crystallite obtained by Scherrer´s equation using XRD [43]). Further details regarding the equipment and the experimental procedures used to characterize the nanoparticles can be found in previous studies [44, 45]. All chemicals were used as received without further purifications.

3.2. Methods 3.2.1. Polymer Evaluation The solutions following the API 63 Standard “Practices for evaluation of polymers used in EOR operations” [46], concerning the agitation speed and total solubilization time. The concentrations of polymeric solutions ranged from 50–1500 mg/L. To guarantee their homogeneity and stability, the solutions were stored in the absence of light and heat for 48 h. The mixtures were stirred for 30 min until homogenization in the absence of light using an HP130915Q mixer from Thermo Scientific (Waltham, Massachusetts, USA). After ensuring the stability of the polymer, the SiO2 nanoparticles were dispersed in the polymer solution and tested various concentrations of nanoparticles (0–10,000 mg/L). To guarantee a homogeneous mixing in the aqueous matrix, the nanoparticles were added slowly until reaching the desired nanoparticle concentration. The polymer sample was characterized in the following properties: density, pH, and infrared spectroscopy and thermogravimetric analyses. The pH was determined using a pH-meter Horiba Navih (Irvine, California) and the density was determined using a 10-mL pycnometer. The Fourier-transform infrared spectrophotometry (FTIR) was performed with an IRAffinity-1S spectrophotometer (Shimadzu, USA) [47] and conducted thermogravimetric analyses of the polymer samples with a Q50 thermogravimetric analyzer (TA Instruments, Inc., New Castle, DE) at a

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heating rate of 20°C/min from 25°C to 800°C under N2 and dry air atmospheres at a fixed flow rate of 100 mL/min.

3.2.2. Isotherms of Adsorption and Desorption According to the procedure described by Guzmán et al. [48], the adsorption tests were performed through in batch mode experiments by fixing the amount of adsorbate and varying the dosage of the adsorbent at temperatures of 25°C, 40°C, and 70°C. For this purpose, different ratios of solution volume to the mass of the adsorbent ( M ) from 0.1–10 g/L. In this case, an initial polymer concentration ( Ci ) of 500 mg/L, which is the typical polymer dosage used in the oil-and-gas industry [49]. It is worth mentioning that the used polymer has self-associative properties and its aggregate size in solution depends on variables such as temperature, pressure, shear rate, and pH, among others. The preparation method consisted of adding the desired concentration of SiO2 nanoparticles to a previously stabilized polymer solution, as described in section 4.2.1, the solutions were stirred slowly for 48 h, which is the time needed to reach the adsorption thermodynamic equilibrium and guarantee adsorbate– adsorbent interaction. The amount adsorbed ( N ads ) in each method is determined by the mass balance using TGA under an air atmosphere from 25°C to 800°C at a fixed heating rate of 5°C/min and an air flow of 100 mL/min. For this purpose, first the nanoparticles containing the adsorbed polymer were separated from the mixture by centrifugation for 2 h at 4500 rpm using a Hermle Z 306 Universal Centrifuge (Labnet, NJ). Next, using cesium fluoride (CsF) [50] at 25°C, the remaining humidity is removed in the nanoparticle samples with the adsorbed polymer using a closed system with a similar relative humidity. All measurements were performed three times. Adsorption experiments by exposing a certain mass of nanoparticles in a fixed volume of liquid solution to varying initial polymer concentrations between 100 mg/L and 1000 mg/L for M values of 0.5 g/L and 3 g/L. The reversibility of the adsorption process was evaluated by constructing desorption isotherms. Before the experiments, any deposited

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(not adsorbed) polymer was removed from the system by washing with deionized water. Then, samples are placed in clean deionized water, using the same M values as those used in the adsorption experiments and continuously and slowly stirred them for 48 h. The remaining adsorbed polymer on the supernatant was determined by TGA and corroborated the results by UV/Vis spectrophotometry using a Genesys 10S UV-VIS spectrophotometer (Thermo Scientific, Waltham, MA) with ±0.001 a.u. of uncertainty in the absorbance measurement. The remaining amount of adsorbed polymer (Nads,rem) was determined as follows:

N ads ,rem  N ads 

CE ,rem V W

(1)

where, CE,rem (mg/L) is the polymer concentration in deionized water after the desorption process, Nads is the amount adsorbed during the adsorption process, and ( V ) and ( W ) are the solution volume and the dry mass of the material, respectively. To prevent solvent evaporation, desorption experiments were conducted at 25°C, 40°C, and 70°C in tightly sealed glass vials 0.8 cm in diameter and 7 cm in length. After the desorption process, the glass vials were placed in dry ice to cool them down instantaneously and then carefully opened them and quickly decanted the supernatant to prevent changes in the amount desorbed.

3.2.3. Retention Test A sand pack was selected to perform the retention test and used clean silica sand as the packing material (Ottawa sand, U.S. sieves 30–40). Before packing, the sand was cleaned with deionized water to remove any dust or surface impurities and then placed it in a vacuum oven at 60°C for 12 hours to evaporate any remaining water. Then approximately 250 g of the sand was transferred to a glass column (inside diameter of 3 cm and length of 30 cm) for packing. The retention test was conducted using a polymer/nanoparticle fluid and polymeric solutions of different concentrations. This was prepared using the first adsorption methodology, whereby first the polymer is stabilized in deionized water and then added

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nanoparticles in different concentrations. The test was performed at 25°C and 50°C under gravitational forces (vertically, with the flow injection from the bottom). Figure 1 shows a schematic representation of the experimental setup, which mainly consisted of a commercial peristaltic pump for injecting the polymer-NpS fluid from the bottom, the packing sand, and the collectors for evaluating the effluent. The flow rate of injection was approximately 10 ml/min.

Figure 1. Schematic of experimental setup retention test at standard conditions.

The effluent was measured by UV/Vis spectrophotometry using a Genesys 10S UV-VIS spectrophotometer (Thermo Scientific, Waltham, MA) with ±0.001 a.u. of uncertainty in the absorbance measurement. In some of the sand pack flow experiments, the distribution of the retained HPAM polymer was determined after an extended flow period by dividing the sandpack into several sections and using TGA to determine the amount adsorbed in each section by its mass balance in air atmosphere

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conditions and varying temperature from 25°C to 800°C at a fixed heating rate of 5°C/min and an air flow of 100 mL/min.

3.2.4. Measurement of Aggregate Size To evaluate the aggregate sizes formed by both the polymer solution at different concentrations and the nanoparticle/polymer system, the measurement is performed using the dynamic light scattering (DLS) technique measurements using a nanoplus-3 instrument from Micromeritics (Norcross, ATL), which was equipped with a 0.9-ml glass cell and the mean aggregate diameter obtained using the Stokes-Einstein equation. 3.2.5. Rheological Behavior and Stability in Time Rheological measurements of the polymer solutions in the presence and absence of nanoparticles were performed using a Kinexus Pro+ rotational rheometer (Malvern Instruments, Worcestershire, UK) with a concentric cylinder geometry and equipped with a Peltier plate for temperature control. Tests were conducted at 25°C and 70°C in a shear rate range of 1–250 s–1. To measure the stability of the polymer solutions in the absence and presence of nanoparticles, the samples were submitted to oxidative and inert atmospheres by dry air and N2 injection, respectively, using a saturator and with a fixed flow rate of 100 mL/min. Samples were aged at 70°C for 14 days and monitored the degradative effects of the polymer solutions via the observed rheological changes in the samples. Each experimental condition set was repeated three times.

4. MODELING 4.1. Adsorption Isotherms The solid-liquid equilibrium (SLE) model on the theory of adsorption of self-associative molecules onto solid surfaces, which is expressed as follows [51, 52]:

Synergy of SiO2 Nanoparticle-Polymer …

CE 

   H exp   , N 1  K ads , m  

199

(2)

where



1  1  4 K , 2K  N

N

(3)



   ads ,m ads  .  N ads ,m  N ads 

(4)

N ads (mg/g) and N ads ,m (mg/g) are the amount of polymer adsorbed onto the nanoparticle surface and the maximum adsorption capacity of the nanoparticles, respectively. C E (mg/g) is the equilibrium concentration of the polymer. The SLE parameters K (g/g) and H (mg/g), respectively, are adsorption constants related to the degree of polymer self-association over the nanoparticle surfaces and Henry’s law, which is related to the preference of the polymer to be in the liquid or adsorbed phase [52].

4.2. Rheological Behavior The rheological behavior of the polymer solutions in the absence and presence of nanoparticles was modeled using the Herschel-Bulkley model [53-55], which is an index of flow behavior ( nH ) that is more or less Newtonian, for which values less than 1 are considered to be pseudoplastic [55]. The consistency index K H (Pa sn) refers to the fluid viscosity and the parameter of viscosity at infinite stress  , (cP).

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  K ( ( n

H

H

1)

)  ,

(5)

The root-mean-square error (RSME%) were used to estimate the goodness of fit using the Solver feature in Excel package 2015 [56, 57] for all the models used.

RSME %  100

1  Exp  Cal    n  Cal 

2

(6)

5. RESULTS To coherently present the evaluation of the above polymer, the results are divided in five sections: polymer characterization, adsorption/ desorption isotherm measurement, retention test, measurement of aggregate size, and rheological behavior.

5.1. Polymer Evaluation Polymer solutions were characterized by density, pH, FTIR spectra, and TGA. the density of the polymer solutions to be 1.163 ± 0.003 g/mL for the range of concentrations evaluated. Similarly, the pH values of the polymeric solutions varied between 7.16 and 7.41. Polymer degradation was evaluated by TGA under oxidative and inert atmospheres, the results of which are shown in Figure 2. It is observed that, due to the oxidation process and thermal decomposition, respectively, the polymer sample undergoes degradation in both scenarios, with mass losses of between 60% and 40% for temperatures ranging between 25°C and 400°C. The degradation is more marked for the oxidation process due to the physicalchemical properties of the polymer than for the inert atmosphere evaluated using nitrogen, as can be seen in Figure 1. Initially, the mass loss in the range between 25°C and 200°C can be attributed to the remaining adsorbed

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Rate of mass loss (%/°C)

water in the sample. Above 200°C, the mass loss can be attributed to the thermal decomposition of the functional groups (amide and carboxylate) and above 400°C, to the decomposition of the C–C bonds from the polymer backbone [58]. The polymer was characterized using FTIR spectrophotometry and Figure 3 shows the obtained FTIR spectrum. The band observed at 3325 cm−1 is due to the free OH- stretching [59]. The weak intensity bands at 3356 and 3170 cm−1 in the HPAM indicates the presence of moisture, which is common in most dried polymers. Also, the bands at 1580 cm−1 and 1380 cm−1 indicate N–H bonds and the existence of C=O bonds [59]. These results are consistent with those reported by Murugan et al. [60]. Also, C–H asymmetric and symmetric stretching vibrations are observed at 2967 cm−1. The weak bands located at 1110 cm−1 and 1010 cm−1 are characteristic of a C–C stretching vibration [61]. 0.9 0.8

Derivate Mass Dry Air Derivate Mass N2

0.7 0.6 0.5 0.4 0.3 0.2 0.1 0 0

200 400 Temperature (°C)

600

Figure 2. Polymer decomposition under oxidative and inert atmospheres. Heating rate of 10°C/min from 30°C–600°C.

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Figure 3. FTIR spectra for the a)HPAM b)HPAM onto nanoparticles.

5.2. Adsorption and Desorption Tests Figure 4 shows the experimental isotherms of HPAM on SiO2 nanoparticles, along with the SLE model at a 25°C fixed initial polymer concentration of 500 mg/L. From Figure 4, it can be seen that the adsorption isotherms follow a Type-III behavior, according to the

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Nads (mg/g)

International Union of Pure and Applied Chemistry (IUPAC) [62]. This isotherm type typically indicates a low affinity between the adsorbateadsorbent at low HPAM concentrations. At high concentrations, the interaction of multiple HPAM layers over SiO2 nanoparticles is favored [62]. The shape of this adsorption isotherm can be attributed to the reduction in the number of active nanoparticle sites available for adsorption by mass unit, which is caused by the increased dosage of nanoparticles impacting the interactions between the available nanoparticles and the polymer. Similar results were reported by Guzman et al. [48], who evaluated the adsorptive process over different surfaces. For a fixed equilibrium concentration of 420 mg/L, a comparison of the adsorption isotherms shows a polymer adsorption amount of 13.3 mg/g. This can be attributed to the intermolecular forces between the most polar components of the polymer aggregate (mainly functional groups) and the silanol groups present in the SiO2 nanoparticles.

14

Adsorption

12

Desorption SLE Model

10 8 6 4

2 0 0

100

200 300 Ce (mg/L)

400

Figure 4. Adsorption and desorption isotherms for a fixed initial polymer concentration of 500 mg/L at 25°C.

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Nads (mg/g)

6

4

2

0 0

100

200 300 Ce (mg/L)

400

Figure 5. Adsorption isotherms obtained for a fixed initial polymer concentration of 500 mg/L and temperatures of 70°C (experimental data figure and dashed line SLE Model).

Table 1. Estimated SLE model parameters for adsorption of polymer on SiO2 nanoparticles, for a fixed initial concentration of 500 mg/L and temperatures of 25°C and 70°C Temperature (°C)

H (mg / g )

K (g / g)

Nads ,m (mg / g )

RSME %

25 70

34.74 151.10

26.03 70.62

4638.45 4018.39

5.82 7.73

Based on the adsorption isotherms at 25°C, adsorption isotherms at 70°C were constructed using the same methodology. Figure 5 shows the polymer adsorption isotherms of the SiO2 nanoparticles at 70°C together with the SLE model fitting. From Figure 5, it can be seen that the amount adsorbed decreased as temperature increased, as influenced by the decreasing interaction forces between the adsorbate and adsorbent. Furthermore, the mean size of the polymer aggregate was affected by

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temperature. As the temperature increases, the aggregate size decreases, so the adsorbed uptake decreases. The SLE model was employed for to describe the HPAM adsorption process onto the SiO2 nanoparticles. As the SLE model showed the better fitting, Table 1 lists the obtained SLE model parameters, in which a clear trend is observed. The adsorption affinity according to the H parameter suggests a high level of interaction. Adsorption isotherms were also obtained by varying the initial polymer concentration at constant nanoparticle dosages with M values of 0.5 g/L and 3 g/L, the results of which are shown in Figure 6. When comparing the results of Figure 6 with those in Figure 5, it is observed a change in the type of isotherm, which is also reflected in the obtained parameters of the SLE model in Table 2. As it can be observed in Figure 6, when the nanoparticles amount is fixed in solutions with different initial concentrations of polymer, the obtained isotherms follow a Type-Ib behavior [62]. Hence, as the polymer aggregate size distribution varies with the concentration, some functional groups on the polymer structure could be hindered by self-associative molecules (i-mers depending on the concentration), resulting in a reduction in the specific interactions with the nanoparticles’ surface and hence in the amount adsorbed. The shape of the isotherm shows a rapid saturation of the available surface area by these aggregates, which results in a plateau of high polymer concentrations. From Table 1, it can be observed that the K parameter of the SLE model is reduced in the Type-Ib adsorption isotherms as compared with the Type-III isotherms (Table 1), which confirms that the adsorbate-adsorbent interactions can be hindered at high concentrations due the polymer selfassociation. It is expected that different polymer loadings in a fixed amount of nanoparticles to result in a different number of specific interactions and hence different degrees of polymer modification in solution. This type of information, based on the adsorption isotherms between the polymer and nanoparticles, provides a better understanding of the interactions between the adsorbate and adsorbent in the formulation of the nanofluid that may be used in the EOR process.

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Table 2. SLE Model estimated parameters for adsorption of polymer onto SiO2 nanoparticles while varying the initial polymer concentration for M values of 0.5 g/L and 3 g/L, and a fixed temperature of 25°C

M ( g / L) H (mg / g )

Kx103 ( g / g )

Nads ,m (mg / g )

RSME %

0.5 3.0

9.33 1.99

93.51 58.65

10.9 9.06

2.02 4.79

60

a) N ads (mg/g)

50 40

30 20 10 0 0

500

1000

1500

CE (mg/L) 35

b) N ads (mg/g)

30

25 20 15 10 5 0 0

500

1000 CE (mg/L)

1500

Figure 6. Adsorption isotherms of polymer onto SiO2 nanoparticles while varying the initial polymer concentration (0–1500 mg/L) for a) M values of 0.5 g/L and b) M values of 3 g/L, and a fixed temperature of 25°C (Dashes line SLE Model).

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Nads (µg/g)

8 6 4 2

Adsorption

0

0

200

400

600

Ce (µg/L) Figure 7. Adsorption isotherms of polymer onto a sand rock while varying the initial polymer concentration (0–1500 mg/L) for M values of 0.1 g/L at a fixed temperature of 25°C.

In the same way that the adsorption isotherms were performed for the polymer onto nanoparticles, the adsorptive effect was evaluated onto a sample of Ottawa sand by simulating a porous medium using the same methodology proposed for the isotherms with nanoparticles. As shown in Figure 7, in general, low adsorption values occurred, due to the inherent characteristics of the polymer and the porous medium. Compared with the values obtained with the SiO nanoparticles, a greater interaction with the nanoparticles is inferred, which in this case is favorable, since it could have exhibited less tendency to cause retention on the porous medium.

5.3. Measurement of Aggregate Size The mean particle size of the polymer in solution was determined by DLS measurements at different concentrations. Table 3a shows the mean particle size of the polymer as a function of the concentration at 25°C, which shows an increasing mean particle size of the polymer aggregate in solution as the concentration increases. This result is commonly observed

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in auto-associative molecules with a polar group and a non-polar backbone, such as the polymer used in this study [48]. Also, from the results in Table 3a, it can be seen that the critical micelle concentration (CMC) of the polymer in solution is approximately of 226 mg/L, based on the observed sudden change in the slope. Table 3a. Mean particle size of polymer aggregate as a function of the concentration at 25°C.

Concentration (mg/L)

Aggregate Size (nm)

50 100 200 300 400 500 600 800 1000 1200 1500

52,095 67,44 93,46 111,443 122,089 139,424 150,729 182,719 200,667 234,652 264,593

The results regarding the droplet size show significant variations between the polymer without nanoparticles, the sample with only nanoparticles, and the nanoparticle-polymer, in which the droplet size of the nanoparticles is smaller and that of the polymer without any nanoparticles is larger. Also, it can be seen an intermediate size for the nanoparticle-polymer mixture. This is beneficial, because the process did not generate a size increase by the addition of nanoparticles, so in the reservoir it will not cause damage by plugging the pore throats. It also shows that with increases in the concentration of nanoparticles, the aggregate size slightly decreases.

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Table 3b presents the particle sizes of single nanoparticles for 400 mg/L, 500 mg/L, and 600 mg/L of polymer mixed with 500 mg/L, 1000 mg/L, and 3000 mg/L of nanoparticles, where it can be seen the decrease in the polymer droplet size with the addition of nanoparticles. The size of the mixture decreases from approximately 135 nm to values near to 90 nm. Table 3b. Distribution of particle sizes with the influence of nanoparticles in different polymer concentrations Sample 400 mg/L Polymer 400 mg/L Polymer + 500 mg/L Np 400 mg/L Polymer + 1000 mg/L Np 400 mg/L Polymer + 3000 mg/L Np 500 mg/L Polymer 500 mg/L Polymer + 500 mg/L Np 500 mg/L Polymer + 1000 mg/L Np 500 mg/L Polymer + 3000 mg/L Np 600 mg/L Polymer 600 mg/L Polymer + 500 mg/L Np 600 mg/L Polymer + 1000 mg/L Np 600 mg/L Polymer + 3000 mg/L Np

dp50 (nm) 118 111 108 104 135 90 96 105 156 129 105 97

The mean aggregate size of SiO2 nanoparticle-polymer system can be affected by both the nanoparticles and the polymer concentrations. Measurements were performed through DLS at 25°C in 400 mg/L, 500 mg/L, and 600 mg/L polymer solutions in the absence and presence of 500 mg/L and 3000 mg/L of SiO2 nanoparticles, the results of which are summarized in Table 3b. The mean aggregate size of the HPAM in solution (500 mg/L) was estimated in 135 ± 10 nm. After the inclusion of nanoparticles, inclusion the aggregate size of the SiO2 nanoparticlespolymer systems was found to be 90 nm and 105 ± 10 nm for SiO2 concentrations of 500 mg/L and 3000 mg/L, respectively. These results indicate that, apart from increasing the polymer solution viscosity, the aggregate size of the system can be significantly reduced by the addition of

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nanoparticles. In polymer flooding processes, this reduction in the aggregate size of the systems to increase efficiency by the inhibition of the residual resistance factor due to pore throat blockage [9].

5.4. Retention Test The retention tests were performed at different concentrations of 500 mg/L, 1000 mg/L, and 3000 mg/L polymer, choosing the concentration of 500 mg/L at different concentrations, with the objective of evaluating the effect of the nanoparticles on the retention phenomena in the porous medium. In Figure 8 it can be seen that the addition of nanoparticles can decrease the amount of polymer retained in the porous medium. Likewise, when the polymer concentration is increased, retention in the porous medium increases, which increases the pore volumes to generate an effluent concentration similar to the initial concentration, which is possibly associated with a larger molecule size of the formed aggregate. As reported by Sorbie [9], this is an important factor in the increase of mechanical entrapment, to the point that it is necessary to inject a greater pore volume until a concentration equal to the initial concentration is obtained. When the polymer passes through a complex network, the molecules can take several routes, some of which can favor entrapment in some of these blocked pores, thereby considerably reducing the flow. This is why the effluent concentration does not easily reach the initial concentration and does so only after the addition of a greater pore volume of fluid polymer. This indicates the presence of some totally blocked sites, such that if a critical entrapment level is reached, complete blockage can occur, thereby lowering the permeability to zero. Now, using the same retention test procedure described above, it is possible to evaluate this phenomenon individually. Further, it is determined the distance along a sand pack sample to determine the retention effect in each zone. As described by Gogarty [22], the distribution of the mechanically trapped polymer along porous media must

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be greater near the inlet and decrease approximately exponentially along the nucleus, as shown in Figure 9, which agrees with the results obtained by Szabo. In this case, for a polymer concentration of 500 mg/L with mechanical retention values ranging between 12 and 16 at the sample inlet and 4 to 6 at the sample outlet, these retention values are consistent with those obtained with respect to static adsorption, as shown in the Figure 7, in which the adsorption is low compared to the result obtained in Figure 10. This shows that the greatest contribution to retention was the mechanical entrapment, with adsorption in the porous medium playing only a minor role. On the other hand, when nanoparticles are included, this retention decreases slightly. This result could be due mainly to the decrease in aggregate size, which reduces the likelihood of polymer entrapment in the pores.

Figure 8. Retention test results at different concentrations of polymer (Pol.) and nanoparticles (Np).

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Figure 9. Distribution of polymer retained along a sand pack after a polymer flood.

5.5. Rheological Behavior In polymer flooding operations, determining the behavior of fluid subjected to variations in temperature and a high degree of agitation by the continuous injection of fluids into a formation is critical to the success of EOR processes. Figures 10a and 10b show the rheological behavior of HPAM in solution for polymer concentrations from 50–1500 mg/L at 25°C and 70°C, respectively, together with a Herschell-Bulkley model fitting. As expected, the viscosity of polymer solutions increases as the concentration increases, which is explained by the self-associative nature of the HPAM molecules [63]. Also, in Figure 10 it can be observed that the viscosity of the polymer solutions decreases as the shear rate increases, which is typical behavior for pseudoplastic materials or shear-thinning [64]. A significant number of fluids like the evaluated polymer (HPAM) deviate from Newton’s law of viscosity in that their response is a function of the applied shear rate as opposed to that of a Newtonian fluid. At a fixed shear rate of 7.8 s−1, polymer solutions reach viscosity values of up to 224 cP for a polymer concentration of 1500 mg/L at 25°C. However, when the

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temperature is increased to 70°C, the viscosity is reduced to 170 cP at 7.8 s−1. The viscosity is reduced by increasing the system temperature or due to changes in the polymer backbone due to increased hydrolysis with heating [65]. Acrylamide polymer groups undergo hydrolysis to form acrylate groups, which increase the ionic character of the polymers at temperatures greater than 60ºC [24]. These results agree with those reported by Beyler et al. [58], who studied the decomposition of polymers by the effect of temperature.

Viscosity (cP)

a 200

1500 mg/L 600 mg/L 500 mg/L 300 mg/L 100 mg/L 50 mg/L Herschell-Bulkley Model

150 100 50 0 0

50

Viscosity (cP)

b 200

100 150 Shear rate (s-1)

200

250

1500 mg/L 600 mg/L 500 mg/L 300 mg/L 100 mg/L 50 mg/L Herschell-Bulkley Model

150 100 50 0 0

50

100 150 Shear rate (s-1)

200

Figure 10. Rheological behavior of polymeric solutions at various polymer concentrations and temperatures of a) 25°C and b) 70°C.

250

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Table 4 summarizes the estimated parameters for the Herschel-Bulkley at 25°C and 70°C. The models show a good fitting of the experimental results with an RSME% 500 > 1000 mg/L of HPAM at both 7 and 14 days. As it can be seen in Figure 6, when different concentrations of polymer are employed for with a fixed dosage of nanoparticles, the amount adsorbed increases as the polymer concentration increases. Hence, it can be inferred that by increasing the amount of polymer adsorbed onto the nanoparticles, the degradation of the polymer solutions will be inhibited.

a

1000 mg/L

100

Viscosity (cP)

100 mg/L

10

1

0

50

b

100 150 Shear rate (s-1)

200

250

1000 mg/L 100 mg/L

Viscosity (cP)

40

1 0

50

100 150 200 -1 Shear rate (s )

250

Figure 13. Rheological behavior of 100-mg/L and 1000-mg/L polymer solutions in the presence of 3000 mg/L of nanoparticles after degradation at 70°C in an oxidative atmosphere for a) 7 days and b) 14 days.

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Table 7. Degree of polymer solution degradation for 100-mg/L and 1000-mg/L polymer solutions in the presence of 3000 mg/L of SiO2 nanoparticles after degradation at 70°C in an oxidative atmosphere for 7 and 14 days SiO2 nanoparticles concentration (mg/L) 3000

Polymer concentration (mg/L) 100 1000

DPD% 7 days 14 days 31.87 52.86 28.63 39.33

A correlation between the amount adsorbed and the DPD% after 7 and 14 days is observed. The DPD% has a direct relationship with the amount of HPAM adsorbed. After 7 days of exposure of the polymer solutions, it can be seen that a linear trend between the amount adsorbed and the DPD% is found. However, after 14 days the correlation deviates from linearity.

CONCLUSION The inclusion of nanoparticles in polymer systems can reduce the degree of polymer degradation caused by temperature and shear effects. In batch-adsorption experiments, the adsorption isotherms of HPAM on SiO2 nanoparticles were successfully obtained. These adsorption isotherms showed Type-III behavior and were well described using the SLE model. Also, the desorption experiment results showed that the polymer adsorption onto SiO2 nanoparticles is irreversible, which would avoid expensive and time-consuming polymer synthesis procedures. Regarding the retention processes that are evident during the polymer flooding process, it is important to take mechanical entrapment into account to a greater extent because this mechanism contributes more than does adsorption in the porous medium. This process is also very dependent on the possible aggregate sizes formed in the aqueous system, which can be considerably reduced by the addition of nanoparticles, thereby helping to decrease retention in the porous medium.

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Degradation tests showed that the degree of degradation of polymer solutions can be significantly reduced by the inclusion of SiO2 nanoparticles. The degradation of the polymer solutions was observed to be dependent on the amount of polymer adsorbed onto the nanoparticle surfaces. The functional groups on the polymer structure may be hindered by the interaction with the nanoparticles, leading to the reduction of specific interactions that result in degradation. Also, it was observed that, apart from inhibiting polymer solution degradation, the inclusion of nanoparticles results in a smaller polymer system, which in turn would reduce any change in the pore throat blockage. Future research should address the effect of formation brine on the efficiency of nanoparticles. Based on the obtained results, it is clear that the interaction of polymers with nanoparticles represents a viable alternative for expanding the range of conditions regarding the use of traditional polymers to reduce possible formation damage, with the added benefit of reducing the degree of degradation, which may lead to more effective and less expensive scaleup processes for large-scale EOR processes.

ACKNOWLEDGMENTS The authors would like to acknowledge COLCIENCIAS for their support provided in Agreement 647 of 2015. They would also like to acknowledge the Universidad Nacional de Colombia for logistical and financial support.

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In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 6

INHIBITION OF THE FORMATION DAMAGE DUE TO FINES MIGRATION ON LOW-PERMEABILITY RESERVOIRS OF SANDSTONE USING SILICA-BASED NANOFLUIDS: FROM LABORATORY TO A SUCCESSFUL FIELD TRIAL D. Arias-Madrid1, N. Ospina2, C. Céspedes3, E. A. Taborda1, Elizabeth Rodríguez-Acevedo1, H. Acuña4, O. Botero4, J. E. Patiño2, Camilo A. Franco 1,5, Richard D. Zabala4, S. H. Lopera5 and Farid B. Cortés1,5,* 1

*

Grupo de Investigación en Fenómenos de Superficie–Michael Polanyi, Departamento de Química y Petróleos, Facultad de Minas, Universidad Nacional de Colombia–Sede Medellín, Colombia

Corresponding Author Email: [email protected].

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D. Arias-Madrid, N. Ospina, C. Céspedes et al. 2

Departamento de Investigación y Desarrollo, Petroingeniería de Antioquia-Petroraza SAS, Sabaneta, Antioquia, Colombia 3 Gerencia de Desarrollo de Yacimientos, Ecopetrol SA 4 Grupo de Ingeniería, Gerencia Nor-Oriente (GNO), Ecopetrol SA 5 Grupo de investigación en Yacimientos de Hidrocarburos, Departamento de Química y Petróleos, Facultad de Minas, Universidad Nacieonal de Colombia–Sede Medellín, Colombia

ABSTRACT The fines migration can occur at different stages during the productive life of a reservoir. Recently, prepared nanofluids have been considered as potential inhibitors due to their physicochemical properties. Therefore, the main objective of this paper is to inhibit the fines migration based on the laboratory studies and conduct a field test for a reservoir of condensated gas and low permeability. This work was performed through a systemic study divided into two steps: 1) Evaluation of the nanoparticles based on silica at room and reservoir conditions in porous media with low permeability, to obtain the optimal concentration of nanofluid for field test, and 2) A trial test on a field of condensated gas and low-permeability sandstones based on the previous results obtained with the reservoir conditions. In this way, two commercial nanoparticles based on silica were characterized by the Brunauer-Emmet-Teller method to determine the surface area (SBET), fill emission scanning electron microscopy (FE-SEM), and dynamic light scattering (DLS). Posteriorly, the nanofluids were prepared using salt water (2%wt of KCl in deionized water) and the two commercial nanoparticles at desired different concentrations (0–20,000 mg/L). The effect of the nanofluids on inhibition of the fines migration was initially evaluated on sandstone beds under normal room conditions. Two bed types were assembled using Ottawa sand: 1) oil-wet and 2) water-wet, which were soaked with specifical nanofluids at different concentrations using a fines suspension based on an average chemical composition from the a field, located in Colombia. The treatments showed a higher capacity of stabilizing the fines for the oil/water-wet beds. The best performance of the nanofluid was achieved when a concentration of 500 mg/L was used. Additionally, a core displacement test (sand-pack) was conducted using injection of a nanofluid at different flow rates. The treatment was very effective in altering the critical rate flow, which was assessed before and after the treatment based on the nanofluid. The results showed an increase of

Inhibition of the Formation Damage due to Fines Migration … 233 400% in the critical velocity relative to the untreated nanofluid. The field test was successful, which showed increases of oil production of 100 bbls per day during the first month of evaluation and a reduction of the production of water around 40% regarding post-pickling.

Keywords: nanoparticle, fines migration, formation damage, adsorption

1. INTRODUCTION Fines migration is one of the causes of formation damage during the production phase in oil wells, mainly in unconsolidated sands [1, 2]. This problem is one of the main causes of the decreased productivity of the reservoir and increased cost in the oil recovery processes. The fine formation damage is mainly due to hydrodynamic factors and physicochemical interactions of the fluid-fines that are concentrated in a matrix form or as free particles [3, 4]. The phenomena of fine migration and swelling of the clays occur simultaneously [5]. The migration of fines refers to the movement of particles present in the porous system due to the shear caused by the high velocities of the circulating fluid [3]. On the other hand, swelling of the clays implies hydration of the considered materials that have high affinity with water [3, 6]. The importance of these phenomena is present in the reduction of the flow by the decreased permeability in the damaged zone, which consequently generates a notable decrease in the efficiency of the production of the well. Consequently, various methods to prevent and remedy the fines migration in porous media have been proposed. One of the most recent and innovative techniques is nanotechnology. Nanofluids contain particles with a size between 1 and 100 nm that allow for their injection into porous media without causing clogging. Nanoparticles have attractive properties that make them optimal for processes in the oil industry, such as high surface area, thermal stability, and being environmentally friendly. This research was performed through of a systemic study divided into two steps. First, the nanoparticles based on silica at room and reservoir conditions in porous media with low permeability were evaluated for

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obtaining the optimal concentration of nanofluid for the field test, based on modifying the attraction-repulsion forces between the particles-particles. Second, a trial test on a field of condensated gas and low-permeability sandstones, based on the previous results obtained at reservoir conditions, was performed. In this way, two commercial nanoparticles were used. The aim of this research was to develop nanoparticles for the inhibition of formation damage caused by fines migration. From tests and field trials, it is possible to determine that fines migration inhibition is favored using nanoparticles, which create a bridge of electrostatic forces between the fine particles and the bed favoring the attractive forces.

2. FINES MIGRATION DAMAGE OVERVIEW According to Bennion [7], formation damage can be defined as “any process that causes a reduction in the original production of oil and gas from production formation.” Based on the above, formation damage is the terminology widely used to refer to the deterioration of the permeability of an oil or gas production formation through different adverse processes [7]. Formation damage is an unwanted operational and economic problem that can occur during the different stages of an oil and gas well. These stages include drilling, production, hydraulic fracturing, and finishing work [7, 8]. The most important treatments for formation damage and determining a more efficient exploitation of the resources are related to their estimation, control, and remediation [9]. Formation damage can be caused by various chemical, biological, hydrodynamic, and thermal interactions with formation pores, particles, and fluids, as well as formation deformations under shear stresses [3, 7, 10]. The presence and migration of fine particles are one of the causes of formation damage during the production phase in oil wells, mainly in unconsolidated sands [1, 2]. The fines migration damage can be caused by a variety of minerals present in the porous medium, such as clays, amorphous silica, quartz, feldspars, micas, carbonates, among others [11]. Fines are particles smaller than 37 µm and have a low density (less than

Inhibition of the Formation Damage due to Fines Migration … 235 1400 kg/m3) which causes pore plugging and productivity-index reduction [11, 12]. The generation of this migration can be caused by several reasons [13], such as a) particles are carried by the fluid entering the formation, such as filtered mud, water injection, completion, and stimulation fluids [13, 14], b) the particles are present in the pore walls and these are mobilized by hydrodynamic forces, which are transported by the reservoir fluid through the porous medium until these are again deposited/trapped in a pore [14, 15], c) the particles are generated by disintegration of the clay grains of the porous medium generated by shear stress in the direction of the flow line that is incompatible with the foreign fluids entering the formation, mainly aqueous fluids [16-18], and d) the particles are generated by pressure depletion, mainly in the unconsolidated sands [2]. All these causes lead to a reduction of the flow channels due to the retention and deposition of the fines particles on the porous matrix, which reduces the porosity and permeability of the porous media and hence possibly reduces the reservoir production [11-13]. Also, the fines generate numerous problems, like destruction of the surface and downhole equipment, environmental issues, downtime and replacement costs, and in extreme cases, a blowout [19]. The fines production is caused by different forces, such as Van der Waals attraction [20-26], Born repulsive [20, 22, 23, 25], double-layer phenomenon [20, 21, 23, 26], and hydrodynamic forces [20, 23, 24], which are the dominant forces in the detachment of the particles from the porous medium [20, 23-26]. When the total interaction energy between the pore surface and the fines becomes positive, the repulsive forces are larger than the attractive forces, and the fines detachment occurs [25-29]. Fines migration is classified as one of the mechanical mechanisms that causes formation damage. These mechanical mechanisms refer to nonchemical interactions between the agents external to the formation and the formation itself. Changes in the properties of the reservoir fluids can also cause mechanical damage. The main mechanisms of formation damage by fines migration are physicochemical, chemical, hydrodynamic, and mechanical, which usually promote or generate the mobilization, migration, and deposition of the fine particles in hydrocarbon deposits. All

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these processes associated with the fine particles constitute causes of formation damage during the different stages of the life of a well and a deposit [1]. The identified sources of fine particles in a hydrocarbon-producing formation are those in which the particles are released by the colloidal forces or by hydrodynamic shear of the fluid flowing through the porous media. They can also be caused by changes in the stress dynamics, overload stress, compression, and dilatation, which causes a loss of the integrity of the rock. The chemical dissolution of the cementing materials in the porous rock by processes of acidification or caustic flooding can also generate fines [30]. Once the fine particle has been generated, there may be three main mechanisms of migration: diffusion, sedimentation, or hydrodynamic effects [31]. The transport of these particles is affected by six factors: molecular forces, electrokinetic interactions, surface tension, fluid pressure, friction, and gravity [7]. In the reservoir, two types of fine particles can be identified: clay and non-clay. The fine clay particles refer to hydrates of aluminum silicates with tetrahedral and octahedral structures [7]. In a porous medium, there are four types of clays: smectic, montmorillonite, illite, kaolinite, and chlorite. Each causes particular problems in training, such as swelling, flocculation, and mobilization. On the other hand, the fine non-clay particles are those minerals, such as quartz, feldspar, and others [7]. Within the clay materials are particles of hydrophilic nature that in the presence of fluids with particular contents of ions and salts, may swell [28]. Consequently, a reduction of the flow channels due to the swelling of the clays is evidenced [4]. On the other hand, the fine particles generated by the other processes mentioned above also represent a potential scenario for formation damage. This is because these particles can be retained or deposited on the porous matrix along the tortuous channels of the flow existing in the medium, causing alterations in both porosity and permeability [32, 33]. The fine particles are characterized by having a grain size that is between 1 nm and 40 μm. Colloidal particles (1 nm) are affected by Brownian diffusion [34]. The distribution of pore size and particles follow the rule of the third, in which any particle whose size is 1/3

Inhibition of the Formation Damage due to Fines Migration … 237 of the pore throat, it will clog and plug; if the particle is between 1/3 and 1/7 of the size of the pore throat, it serves as a bridge externally and the smaller particles less than 1/7 will enter but not fall into the pore network [35]. Table 1 shows the forces present in the transport, attraction and repulsion mechanisms of the fines in the porous medium. Within the related forces in the transport mechanisms, the main variables that dominate the behavior of the suspended particles in the porous medium are: the particle and grain diameter of the porous medium, the convective velocity, the density of the particle, the density and viscosity of the carrier liquid, the absolute temperature, and the acceleration coefficient of gravity [35, 36]. The forces by the transport mechanisms can be classified as inertia, gravity, centrifugal, diffusion, and hydrodynamic forces. The inertia force in a particle is that force that forces it to maintain the movement in a straight line. Equation (1) presents the dimensionless expression for the inertia force [32]. According to Stokes’s law, the frictional force dominates the movement of very small objects. The particles tend to move in the direction of the force of gravity as a product of the density difference between the particle and the carrier liquid [36]. The velocity of a spherical particle subjected to Stokes law is given by Equation (2) [37]. Depending on the light or heavy character of the particles, the gravity force can act up or down. If the particles are light, gravity acts upwards, manifesting a buoyant behavior. On the other hand, if they are heavier, gravity acts downwards, showing a tendency to settle. The force of gravity can be expressed by a dimensionless group that relates Stokes velocities and convection velocities, as shown in Equation (3). The centrifugal force appears when describing the movement of a body in a rotating reference system and it is a product of angular velocity and radius. The centrifugal forces are created by the external acceleration of the system and can be expressed dimensionlessly as shown in Equation (4) [37].

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Table 1. Classification of the forces according to different mechanisms. Taken from [35]

Inertia force

Gravitational force Mechanisms of transport

Centrifugal force

Diffusion forces

Mechanisms of attraction Repulsion mechanisms

Van der Waals forces Cutting forces Double layer forces

ρs ϑa d2 18μD ϑs = (ρs − ρ)gd2 /(18μ) I=

(ρs − ρ)gd2 18μ ϑa (ρs − ρ)Rw 2 d2 Gc = 18μ ϑa KT D= 3πμd 3πμdDϑa Pe = , π = 3,1459 TK K = 1,38 ∗ 10−23 = constante de Boltzmann 1 s−2 Fvw (s) = Fn ( ) 2 (s − 2) λ̅ dv τ=μ dr exp[−kd(s − 2)] FR (s) = 1 + exp[−kd(s − 2)] Gg =

(1) (2)

(3) (4) (5) (6) (7) (8) (9) (10)

On the other hand, the diffusion force refers to the random motion observed in some microscopic particles that are in a fluid medium. These particles are less than 1 mm in diameter. This phenomenon of irregular motion of the particles in a liquid medium that causes them to be randomly dispersed is called Brownian motion [38]. The mathematical description of this diffusivity of fine particles is described by Einstein [39]. The diffusion force can be expressed by the number of Peclet, as the ratio between the convection velocity and the average Brownian velocity, as shown in Equations (5), (6), and (7). Finally, the hydrodynamic forces of a fluid are shear and pressure forces [31, 40]. Numerous theories explain that during the flow of a fluid, the secondary circulations can be formed around the particles. These can generate off-balance hydrodynamic forces acting on

Inhibition of the Formation Damage due to Fines Migration … 239 the particles to move them through the flow field [33]. A suitable expression for the rigorous description of this phenomenon is not available. Within the forces related to the mechanisms of attraction, we find Van der Waals forces, which are the attractive or repulsive forces between the molecules (or between parts of the same molecule) other than those due to an intermolecular bond (ionic bond, metallic bond, and reticular type covalent bond) or the electrostatic interaction of ions with others or with neutral molecules [37]. This force is expressed by Equation (8). The frictional force is that which originates between two surfaces in contact, and which opposes the relative movement between both surfaces (dynamic frictional force) or the force that opposes the beginning of the slip (static frictional force). It is generated due to the imperfections, mostly microscopic, between the surfaces in contact [37, 39]. In the porous medium, it occurs when the particles approach the surfaces of the grains by experiencing a resistance to the flow product of the displacement of the liquid radially as they adhere to the surface of the grain. On the other hand, the forces related to the repulsion mechanisms are classified in shear and double layer forces. The shear force is the force of friction or drag. When the shear stress of the liquid flowing on the deposited particles creates a shear force greater than those acting between the particles and the surface of the grain, the particles can detach and migrate [41]. This force is presented in Equation (9). While double layer forces can occur between objects charged through liquids, usually water. The magnitude of these forces increases with the surface charge density (or surface electrical potential) [35]. These forces are created due to the ionic conditions of the medium, related to the measurements of pH, and the ionic strength [42]. When the surfaces of the particles and grains carry the electrostatic charges of the same sign, they repel each other [43]. The repulsion force is expressed by Equation (10). When the ionic strength is greater, then the double layer thickness is smaller, and therefore the thickness of the double layer of the Debye reciprocal is greater. The repulsion force between particles is defined by the zeta potential, which determines the measure of the electric force between atoms, molecules, particles, and cells in a liquid. This potential is a physical

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property for any particle that is in a suspension. The surface forces between the particle and the medium are of great importance because of the microscopic size of the colloid. If any of the states of the matter is finely dispersed in another, then there is a colloidal system. It is possible to modify the characteristics of a suspension by understanding the interactions of the particles with each other [27, 44, 45]. The charge of the particles can be controlled by the modification of the medium. These changes may be by modifying the pH of the medium or by loading the medium with ionic species. Another technique is the use of agents with an active surface, which adsorbs on the surface of the colloid and changes their characteristics [46, 47]. In the process of the damage of formation generated by the fine particles, certain mechanisms are developed in which phenomena of generation and retention of the particles are involved. These phenomena are influenced by the movement, expulsion, release, and subsequent retention of the rock fragments in the porous medium, which causes the deposition of the particles, the blockage of the pore throat, and the formation of a crust. Particle processes can be classified into two groups: external processes and internal processes [7]. External particle processes refer to the processes developed on the face of the formation. The processes of internal particles are those that develop in the porous medium. These processes are classified into three other groups [7]: A) Pore face: These processes include the deposition and detachment of the particles. B) Pore throat: The plugging and de-positioning of the conduction channels between the pores. C) Pore volume: Crust formation, migration, chemical reactions, rock deformations, releases of fine particles by chemical dissolution of the cement. In general, the mechanisms of generation of fine particles present in the deposit could be summarized in three processes. The motion of the

Inhibition of the Formation Damage due to Fines Migration … 241 particle is generated from the hydrodynamic force exerted by the fluid in the porous medium [7, 48], as shown in Figure 1.

Figure 1. Hydrodynamic mobilization. Adopted from [7].

Second, the particle is ejected from the matrix of the rock in the colloids that are released after the union of several fine particles, as shown in Figure 2.

Figure 2. Colloidal expulsion. Adopted from [7].

Finally, unlike the colloidal expulsion, the particle is released from the matrix due to the loss of integrity of the same, by processes of cement dissolution, rock compression, and formation, as illustrated in Figure 3.

Figure 3. Cement dissolution processes, rock compression, and formation. Adopted from [7].

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Figure 4. a) Surface deposition representation. b) Pore throat blockage. Upper image: Plugging and sealing, central image: restriction of flow, and lower image: bridging. c) Pore filler, internal, and external crust formation. Top illustration: internal crust formation, central illustration: pore filling, and lower illustration: external crust formation. Courtesy of [7].

Also, three main mechanisms have been defined for the retention of fine particles in the pores. These are surface deposition presented in Figure 4a, pore throat block presented in Figure 4b, and filling and crusting in the pore shown in Figure 4c [7, 49]. The clays have interlaminar spaces that are hydrated or dehydrated. Although these processes occur regardless of the type of change cation, the degree of hydration depends on this cation and the minimum charge on the sheet. When water is absorbed in these interlaminar spaces, swelling occurs [44]. For the formation of the clays, the minerals that form in hydrothermal, metamorphic, and sedimentary conditions become unstable on contact with ambient conditions and atmospheric actions, and when subjected to interaction with substances such as CO2 and H2O, they generate exothermic reactions [50]. The formation process of the clays is developed in basically three stages: weathering, sedimentation, and diagenesis. Weathering is defined as a process that causes destruction, i.e., fragmentation involving either wetting and drying, or a freezing and thawing process [7]. On the other hand, this is the hydrolysis process in which the primary minerals interact with the water to form new minerals. This activity becomes even more intense in the presence of heavy rains and temperatures. The weathering process does not include the mechanisms in

Inhibition of the Formation Damage due to Fines Migration … 243 which the generated fragments are displaced. On the other hand, sedimentation is a process by which the particles are subjected to stratified accumulation, after being transported by different agents [51]. In sedimentation, the clay minerals formed above may be affected and undergo some changes, which vary depending on the deposit environment. Fragments and the clay materials are transported to sedimentation basins [51]. Finally, diagenesis is defined as the set of processes that act to modify the sediments after their deposition. It is produced from the surface conditions to depths of burial where the temperature reaches about 250°C. However; these values are not uniform and are highly dependent on internal geodynamics [52]. During the burial stage, the minerals are recrystallized. The sediments can reach thicknesses of up to 4,000 m and as this accumulation increases, so does the pressure and temperature. Clay minerals are affected in different ways, for example, vermiculite, kaolinite, and montmorillonite tend to disappear, while chlorite and illite increase [52]. To classify the clay types, the following factors of the clays are defined: composition, both clay and non-clay minerals (including silicates, oxides, gels, etc.), texture (granule size, orientation, compaction), molecular structure (tetrahedral or octahedral), and the arrangement of their layers (face-to-face) [52]. The clays in hydrocarbon deposits are the allogeneic and autogenic types, such as illite chlorite, kaolinite, and montmorillonite [52]. At present, several mathematical models are known that describe the behavior of the fine particles when they are present in the deposit. The models are classified according to the process that the fine particles present in the deposit. There are models that describe the generation of the fine particles, models that describe the retention of the particles, and mathematical models that combine the two aforementioned models. The mathematical models that describe particle generation are the Donaldson and Baker model [53], the Muecke model [12], and the Khilar and Fogler model [16]. The Donaldson and Baker model, proposed in 1977, analyzes the particle transport process based on the fact that the colloidal forces are particle transport processes, becoming a mathematical and statistical model, and allows one to determine, for the selected

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operating conditions, the fraction of the pores that are plugged, the assembly required to perform the slurry displacement of the fines, and how to obtain a concentration of a given size range [53]. The second model, proposed by Muecke in 1977, describes the movement of the fine particles in porous media micro-models. The model demonstrates that the transport of the particles by the fluids that move through the pores is influenced by the wettability of the particles and the fraction of the surface pores that have similar wettability [12]. Finally, the Khilar and Fogler model developed in 1981, describes that the clay particles are released only when the salt concentration is lower than the critical salt concentration; these clay particles with a size between 1 nm and 100 nm remain dispersed in the sweet water and flow until they are deposited in the pore decreasing permeability [16]. As explained above, other mathematical models describe the behavior of the deposited fine particles, including the Sharma and Yortsos model [54, 55], the Baghdikian, Sharma and Handy model [56], the Chauveteau, Roque and Renard model [57], and the Chauvetau, Nabzar and Cost model [58]. The model proposed by Sharma and Yortsos in 1986 describes quantitatively the behavior of the sandstone after the fine migration occurs. It allows one to find the profiles for the particle’s concentration, pore size distribution, and permeability reduction [54, 55]. The model proposed by Baghdikian, Sharma, and Handy was developed in 1987 and is based on the relative importance of the effect of factors such as pH, ionic strength of the suspension and concentration of the ends in the suspension. Considering these effects, the model allows measurement of the pore size distribution, and monitors the permeability and particle concentrations in the fluid [56]. The model proposed by Chauveteau, Roque, and Renard in 1995 describes the deposition of the fine particles and the plugging of the pore grooves. The model is based on the surface and hydrodynamic forces, which can induce or prevent the retention of the fine particles, depending on the balance of forces at the capture site [57]. Later, Chauveteau, together with Nabzar and Coste in 1998, proposed a model that is based on the relative importance of the forces involved in the various processes of

Inhibition of the Formation Damage due to Fines Migration … 245 deposition. In this way, the different deposition regimes are characterized by the values of a few dimensionless numbers [58]. The latest models proposed to describe the behavior of the particles combined with the behavior of the particles that are generated and retained, allowing a much more complete description of the phenomenon that occurs when there are fine particle processes in the porous medium. Among the models is the Davidson model, which describes the movement of the particles in the porous media about the identification of the depth of penetration of the particles into formations and the rate accompanied by the decreasing injectivity [59]. Davidson, at the end of his model, concludes that when the fines are similar in size to the pore, they are retained at the entrance of the porous medium and it is plugged, and when the size of the fine is much smaller than the pore size, it is deposited on the surfaces of the pore within the porous medium, reducing the flow area and therefore increasing in velocity. This process continues until, due to the increase in velocity, the removal of the fines by friction equals the deposition and the concentration of the suspension at the exit becomes equal to that of the entrance in the porous medium, and at low speeds, there is a greater possibility of settlement of the large particles than the small ones, because the latter are subjected to a greater velocity gradient due to their size. At high speeds, the dragging possibilities are similar [59]. The model proposed by Gruesbeck and Collins is based on the representation of particle distributions and pore size by partitioning the porous medium in any cross-section parallel to the plugged and uncapped pathways. It describes a wide class of filtration and trawling phenomena and shows that the entrainment and deposition of the fines are mechanisms that can cause abnormally low productivity and are phenomena restricted to the area near the well [60]. Khilar and Fogler propose another model that is based on two parameters derived from the equations of the velocity of particle release and particle capture, which are correlated with the flow rate and the temperature. Later, Fogler together with Rege propose a model in 1983 in which they describe a porous medium represented by a network of nodes connected by loops and trace the particle when it moves through the network. Also, they approximate the loops to cylindrical tubes and the

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nodes to spheres. The model allows one to determine the degree of filtration necessary to avoid damage to the injection wells during the water flooding [61]. Wojtanowicz, Krilov and Langlinais described the behavior of the flow channels using the hydraulic tubes to obtain the permeability behavior over time. From this model, one can describe the blockage mechanism of the pores caused by the particles and the mechanism of release and capture of the fines [31]. In general, in the diagnosis of fine-particle formation damage, the most complete and accepted model is the Civan model, which has been changing over the years, adding, with each update, more parameters, and phenomena for diagnosis of the damage. From the outset, it was considered as a phenomenological model, in which all phenomena that govern the particle processes are based on fundamental conservation laws as described in [7, 49, 62, 63]. They consider the combination of the swelling effects with the migration and retention of the fine particles in porous media during the flow to predict the reduction of permeability [64-66]. The model includes the swelling and capture of the clay particles from the surface of the pores by fluid shear [66]. It considers two different sources of particles: those generated within the porous medium and others previously deposited from the flow of the suspended particles [64, 67]. Civan considers the effect of fluid acceleration during the construction of the flow channels by formation damage [7, 65]. Also, it classifies the particles of the formation that are exposed to the solution in the porous spaces in two groups: inflatable and non-inflatable, due to the difference in their mobilization rates [66]. The particles suspended in the fluid can be redeposited and again be entrained during their migration through the porous medium; the rates of re-deposition and the new entrainment must obey a different order of magnitude that the particles are entrained in the first time. The clays can absorb water, and subsequent swelling causes the porosity to be reduced until they are mobilized with the fluid. Subsequently, a field-scale radial flow is proposed to simulate the formation damage in the area near the well in real field conditions [67, 68]. Finally, the phenomenological model proposed by Civan describes the different processes that cause fine formation damage using mathematical

Inhibition of the Formation Damage due to Fines Migration … 247 models, considering the factors, such as temperature and the transport of particles by advection and dispersion [67, 69]. Numerous advances in research have been made to evaluate and mitigate this type of training damage. We have proposed models that allow one to calculate and quantify the damage formation based on the solutions of the equations of steady flow, the concentration of the fines and critical radius, among other parameters [70, 71]. Another type of model focuses on calculating the proportion of the fine particles that reduce the permeability based on a fine particle migration flow channel model [72]. To prevent this type of damage, numerous technologies have been implemented, such as the use of clays as a control element [73], special polymers [74], nanofluids [75], among others [60, 76]. Among the damages caused by the clay minerals, it is possible to find those associated with the migration of the fines, the swelling and hydrothermal reactions [77]. Many fines’ control agents have been developed to minimize the damage associated with the clay minerals, having wide application in acidification, fracturing, sand control, well completion, and improved recovery methods [78, 79]. The study of the different control agents focuses on the agents of an inorganic and organic nature. In the 1960s, the first inorganic stabilizers were developed [80, 81], in the 1970s it was the organic polymers [82, 83], and between the 1980s and 1990s were the complex organic polymers [84, 85]. The action mechanism of the stabilizers is to neutralize the negative charge that the clays have on their surface using cations, which can be simple or complex polymerics. Within the simple cations, we can find Ca2+, K+, NH4+, among others [77]. These cations in sufficient quantity can stabilize the swelling and migration of the fines, but their effect is temporary or reversible because they are prone to be interchangeable with the Na+ ions. On the other hand, polymeric cations can permanently stabilize the migration and swelling, because they cannot be exchanged for simple cations [74]. Stabilizers are classified according to their chemical composition and molecular structure. The two major groups are organic and inorganic. Inorganics are classified into three classes: simple inorganic compounds,

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simple cationic polymers, and steam additives. On the other hand, organic compounds are classified into four classes: simple organic compounds, cationic organic polymers, organic anionic polymers, and nonionic organic polymers Inorganic cationic polymers are made from salts of multivalent metal cations, such as zirconium, chromium, and aluminum. These metals are hydrolyzed in a solution of polynuclear complex with a high-positive charge. Aluminum hydroxyl is the most important polymer because the electrostatic attraction forces between the positive charge of the polymer and the negative charge on the clay surface are very strong [79]. Cationic organic polymers include all positively charged organic polymers, such as the poly quaternary amine [76] and the poly ammonium dimethyl methylene chloride [77]. Due to their good properties, the organic polymers are good stabilizers of the clays; they can adsorb on the surface of the silicates without being able to be replaced by inorganic cations, thus promoting a permanent stabilization [83]. Additionally, these polymers have a high resistance to variable conditions. They are resistant to any pH, are soluble in aqueous solutions and they are not in the hydrocarbons, that is, in the stabilization process, the fines get trapped in the wetting phase (water) [77]. Different tests have been reported in the literature evaluating the effectiveness of these polymers [79]. Among the cases reported for inorganic polymers is that of the Gulf Coast, where the formation lost 90% of its permeability when the concentrated brine was replaced with diluted water [86]. This formation was treated with OH-Al, and the results showed that the sand did not continue to vary its permeability and was resistant to the overflow of distilled water [77]. Blenvins et al. [87] reported that after the use of OH-Al treatment in 36 wells on the Gulf Coast in southern Louisiana, production over a 17-month period increased by 532,000 bbl and that the use of this treatment in acidification processes prolongs the effectiveness significantly. For organic polymers, Borchardt and Yen [85] reported two significant cases, one case at Fordache Field, Louisiana [88] and one in an offshore area in Louisiana [89], where the formations were shown to be treated with organic polymers after an acid treatment, showing

Inhibition of the Formation Damage due to Fines Migration … 249 in both cases that the behavior turned out to be much better with the post flow of the polymer than without it. The wells typically exhibit a decline in yield of between 50 and 75% once treatment was applied and production restored, this was maintained for three years without episodes of fine migration [90]. These studies show that organic treatments prove to have small effect on the stabilization when the migration of the fines is the product of mechanical effects [91]. Hence, new efficient and cost-effective technologies need to be implemented to inhibit formation damage by the fines migration. Taking advantage of the properties offered by the nanoparticles, including their high surface area/volume, the nanoparticles and the so-called “nanofluids” are presented as an alternative to improve the oil and increase the productivity of the reservoir.

3. NANOPARTICLES FOR INHIBITING THE FORMATION DAMAGE BY FINES MIGRATION Nanotechnology is defined as a development that allows the construction and manipulation of materials at the nanoscale [92]. In recent years, nanotechnology has gained importance in various areas, such as the storage, production, and conversion of energy [93, 94], improving agricultural productivity and food processing [95-97], water treatment and remediation [98-101], medicine [102, 103], air pollution [104, 105], construction [106, 107], and the detection and control of pests [108, 109]. In the oil industry, nanoparticles have been used in various applications, such as bitumen upgrading and crude oil recovery [110, 111], optimization of drilling fluids [112, 113], and fines migration control [114, 115], among others. Some authors have used various techniques to inhibit the fines migration in the reservoir, such as chemical stabilizers [18, 116-118], ionic stabilizers of clays [117, 119, 120], water soluble polymers [18, 120, 121], and a thermally stable chemical system called the zeta potential altering

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system [23, 27, 122]. Nanoparticles emerge like an excellent alternative for controlling the fines transport due to their high retention capacity [12, 14, 27-33] given by properties, such as high surface area to volume ratio [3437], high retention affinity due to their surface energy [38-40]. In addition of their dispersibility [41-43] and flexible performance to obtain a particular size and chemical composition [28, 29, 37, 44-46]. The mechanisms of fines retention based on nanotechnology are due to the interactive forces between the surfaces of the fines particles and the nanoparticles used like an inhibitor. The interactive forces between the fines particles and the nanoparticles are caused mainly by Van der Waals (VWF) forces [10, 20, 26, 123, 124] and/or electrostatic forces (EF) [20, 23, 26-28, 125]. Huang et al. [21, 126] performed a study using magnesium oxide (MgO) nanoparticles for enhanced oil recovery by stabilizing the clays and the fines by applying a water flooding method. This study was conducted in a sand-pack test, pumping approximately 5 wt% KCl in each flow rate and recording the differential pressure to determine the influence of the nanoparticles on the formation stability. A 20/40 mesh of sand and bentonite was used for the sand-pack. A qualitative test evaluated the fines migration through the sand-pack with the support of a filter paper at atmospheric conditions. The results showed a reduction in the pressure drop of around 3 psi in the presence of the treatment compared to the sand-pack without the nanoparticles. Indeed, the effluent obtained from the treated sand-pack with the nanoparticles has a lower fines amount than the virgin sand-pack. The authors argue that the capability of stabilizing the clay migration of the MgO nanoparticles is caused by their highly positive charge combined with other surface forces such as VDW forces. Also, Huang et al. [127] studied the addition of the nanoparticles in a fracking fluid (FF), which was evaluated in the inhibition of the formation damage for the invasion of the FF to the reservoir. The authors do not specify the chemical nature of the nanoparticles nor the nature of the fracturing fluid used. Only, they reported a ratio 1 to 1,000 wt% between the nanoparticles and the proppant. Researchers conclude that the nanoparticles have the ability to prevent the fines migration because they have significantly higher surface

Inhibition of the Formation Damage due to Fines Migration … 251 forces, including the VDW forces and electrostatic forces that adhere to the proppant surface during the pumping. More recently, Huang et al. [115] continued their research about hydraulic fracturing from a qualitative laboratory test, which consists of fines suspension flow through a proppant pack with coated nanoparticles. The retention capacity of the nanoparticles is analyzed from the flow of a clean solution in the proppant pack. From the effluent, the investigation demonstrates that the coated nanoparticles set the formation fines on the proppants. Belcher et al. [127] conducted a study with nano-proppants where it is possible to improve the production and prevent formation damage by controlling the fines migration in the offshore field located in the Gulf of Mexico. The pay zone measured depth is 15,760 ft to 15,860 ft and the temperature is about 22°C. The FF was applied after a 14-month production period because of the oil production decline from about 7,500 BOPD to 2,200 BOPD. After the treatment injections to the reservoir, production increased slightly. At three months after the treatment, the average production was 3,200 BOPD oil and after six months it was 2,800 BOPD, without reporting any associated fines problems. The results indicate that the nanoparticles attached the fines to the proppant and improved the well productivity, preventing formation damage and other associated problems. Other researchers of fines migration and its impact on the formation damage have been Habibi et al. [128], using different nanomaterials in packed beds to control the fines migration. The authors used alumina (Al2O3), silica (SiO2), and MgO nanoparticles for inhibiting the fines migration. Evaluating the efficiency of the nanomaterials consisted of two tests; the first uses a synthetic porous medium with different types of nanoparticles in the soaking fluid to study the effect of the matrix soaking on the fines fixation at atmospheric pressure. The second test uses a flooding process using a nanofluid with MgO and a synthetic porous medium with a permeability of 18 Darcy in a core holder. The temperature and pressure of the test were not specified. The porous medium is placed in a vacuum for 3 h, and distilled water was used as the reference test. The effluent was collected and measured by spectrophotometry to determine the efficiency of the process. The nanofluid was prepared with a specific

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amount of nanoparticles dispersed in distilled water. The first test shows that the nanoparticles of MgO are the most effective to control the fines migration with adsorption efficiencies of 4.3, 9.3, to 12.8% for alumina, silica, and MgO, respectively. The second test shows a reduction of the fines migration with increasing concentration of the nanofluid evaluated from 0.05 to 0.2 wt %. Besides, from 0.2 wt % concentration of nanoparticles in the injection test, the researchers argued that the fines do not move from the surface (even at high rates) due to the attractive forces between them and the porous surface. This was determined from an injection test from 800 mL/h up to 1,300 mL/h where the effluent fines concentration was 0 g/mL. Ogolo et al. [129] evaluated the chemical nature of nine nanoparticles dispersed in different fluids for the fines control in the sand-pack at atmospheric conditions. The nanoparticles used were nickel oxide (Ni2O3), aluminum oxide (Al2O3), zirconium oxide (ZrO2), zinc oxide (ZnO), iron oxide (Fe2O3), silicon oxide hydrophobic (SiO(OH)), silanol treated with silicon oxide (SiO2), and tin oxide (SnO2) and the dispersing fluids were distilled water, diesel, ethanol, and brine with a salinity of 30 g/L. The tests were performed in the sand-pack with and without the presence of crude oil. The results show that brine is the best nanoparticle dispersing fluid in trapping the fines compared with distilled water and ethanol in the absence and presence of crude oil, because brine is naturally present in formations and therefore is more compatible with crude oil and formations. However, they do not analyze the influence of the ions present in the brine on the behavior of the nanoparticles. Also, the researchers concluded that the nanoparticles of nickel oxide present the best results, followed in order by aluminum oxide > zirconium oxide > silanol treated with silicon oxide. In recent years, Assef et al. [23] analyzed the use of nanoparticles as a fines migration control method to improve water injection at low salinity and alkaline conditions. The chemical environments of low salinity and high pH are very unfavorable for the retention of particles caused by electrostatic repulsion forces between the rock surface and the particles. The authors concluded through zeta potential and turbidity analyses that MgO nanoparticles can modify the zeta potential of the porous medium and thus prevent fine migration

Inhibition of the Formation Damage due to Fines Migration … 253 induced during low salinity conditions. They showed that MgO nanoparticles on the beds surface modified and increased the zero point of charge from around 3 to around 9, which justifies the retention of particles under alkaline and atmospheric conditions. Besides, the treated medium presented around 97% of the retained particles in the presence of divalent and monovalent salts. Nanofluids, like the method for the inhibition of fines migration have been widely studied, always generating positive results. However, to the best of our knowledge in the specialized literature, there are no reported studies which have used nanoparticles for the inhibition of the fines migration in condensated gas reservoirs with low permeability. Therefore, this chapter proposes the evaluation of two commercial nanoparticles based on silica to inhibit the fines migration at room and reservoir conditions for two low-permeability porous media, which were initially oil- and water-wet. The best nanoparticles at reservoir conditions altering the critical velocity in the porous media are caused by the variation in the attraction-repulsion forces. The pilot test was performed on a condensate gas field and low-permeability media with the injection of a nanofluid based on the results of the displacement test under reservoir conditions. The results of the trial test in the Colombian field are presented, showing an increase of oil and gas production and the inhibition of the fines migration based on the nanofluid chosen from the above experimental tests in the laboratory.

4. MATERIALS AND METHODS To determine the best nanoparticles in inhibiting the fines migration, two tests under laboratory conditions were performed, namely: i) fines retention tests in Ottawa sand beds to evaluate two different nanoparticles in water- and oil-wetted systems and using five different concentrations of silica-based nanoparticles; and ii) critical rate tests under reservoir conditions using a core from the selected field and using the nanoparticles with the best performance in the fines retention tests. Further, the

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nanoparticles were used in the field trial in a determined well of the selected field. Table 2. Estimated SBET and mean particle size of the selected nanoparticles Material SSN PSN

SBET ± 2.17 m2/g 389 130

d50 DLS particle diameter ± 2 nm 9 30

4.1. Materials 4.1.1. Nanoparticles Two commercial silica-based nanoparticles were employed for the laboratory tests and were purchased from Sigma-Aldrich (USA) and Petroraza SAS (Colombia) and are known as Sigma-Aldrich silica nanoparticles (SSN) and Petroraza silica nanoparticles (PSN), respectively. The nanoparticles were characterized by N2 physisorption at −196.15°C or particle size and SBET, respectively. An Autosorb-1 from Quantachrome was employed for the SBET estimation. The dynamic light scattering (DLS) measurements were performed using a nano plus-3 from Micromeritics (Norcross, ATL) set at 25°C and equipped with a 0.9 mL glass cell. Table 2 shows the estimated values of the SBET and the particle size of the selected nanoparticles. 4.1.2. Reagents Toluene (99.5%, MerkK GaG, Germany) and methanol (99.8%, Panreac, Spain) were used for sand and core cleaning before the tests. Furthermore, n-heptane (99%, Sigma-Aldrich, USA) was used for isolating the asphaltenes from an extra-heavy oil of 6.4°API and viscosity of 4.32 х 103 cP at 25°C with an approximate content of 16 wt%. The extracted

Inhibition of the Formation Damage due to Fines Migration … 255

asphaltenes were used to induce an oil-wet state in the sand-pack for the fines retention tests. In addition, BaSO4 (99%, Sigma-Aldrich, USA), CaCl2 (99.9%, Sigma-Aldrich, USA, Na2CO3 (99.9%, MerkK GaG, Germany), and NaCl (99%, MerkK GaG, Germany) were used for the synthetic brine preparation. The brine composition was: alkalinity of 578 mg/L, 240 mg/L of SO4, 10 mg/L of Ba+, 98 mg/L of Ca+, and 1348 mg/L of Cl-, and was used for the fines suspension preparation for the displacement tests. Deionized water was also used for the fines suspension and the brine preparation.

4.1.3. Sand-Pack, Porous Media and Fines Suspension Ottawa sand (Minercol S.A., Colombia) of 30/40 and 10/20 mesh in a 50 wt% ratio of each mesh was used for the preparation of the porous media in the low-pressure tests. The fines suspension was prepared based on an average composition from the selected oil field [130] by adding 50, 43, and 7 wt% of kaolinite (Minercol S.A., Colombia), quartz (Minercol S.A., Colombia), and illite (Minercol S.A., Colombia) particles with a size around 37μm in deionized water. The fines concentration used was 2,400 mg/L, which was sonicated for 2 h at 25°C and subsequently kept under stirring at 500 rpm to maintain a homogeneous distribution of the fines in the solution during the tests. The density, viscosity, and pH value of the fines suspension at 25°C were 0.9956 g/cm3, 1.37 cP, and 9.8, respectively. For the tests under reservoir conditions, a core-plug from the BC formation of the selected well was used. Figure 5 and Table 3 show the obtained pore throat size distribution (PTD) (obtained by mercury porosimetry, AutoPore IV 9500, Micromeritics) and the core-plug characteristics, respectively. The test showed a bimodal behavior with higher frequencies in the radii of 0.35 and 1.4 µm, which ensures best flow conditions. Based on the results of the PTD, the nanoparticles size for the retention of the fines was selected to avoid damage by locking, bow, or plug pore throats.

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Table 3. Properties of the core used in the critical rate tests Property Length (cm) Diameter (cm) Pore volume (cm3) Porosity (%)

Value 5.9 3.8 3.4 5.1

Figure 5. Pore throat size distribution.

4.2. Methods 4.2.1. Fines Retention Test: Low Pressure Fines retention tests were performed in porous media in the absence and presence of nanoparticles. The porous media were prepared with 70 g of Ottawa sand with 30/40 and 10/20 mesh in a 50 wt% ratio of each mesh. Water- and oil-wet porous media were used. Water-wet sand-pack was washed with excess distilled water and further dried at 120°C. The oil-wet porous medium was submitted to an aging process using a Colombian extra-heavy crude oil. For this purpose, a solution of n-heptane/oil in a ratio of 40 mL/1 g was prepared [131]. Then, the sand was immersed in the solution at 40°C for 24 h with constant stirring at 500 rpm. Subsequently,

Inhibition of the Formation Damage due to Fines Migration … 257 the sand was removed from the solution and further dried at 120°C before being washed with n-heptane to remove any residual oil in the sand. Next, the sand was washed with distilled water. Finally, the sample was dried at 120°C to remove any remaining water and solvent. For the porous media treatment with the nanoparticles, the sands were immersed in distilled water-based suspensions with 1 wt% in distilled water of the selected nanoparticles according to the sand weight, for 6 h at 60°C and 500 rpm, and subsequently dried at 120°C for 24 h to remove any remaining water. The wettability test was conducted to verify the change of the porous medium wettability. A blind core was prepared by compacting the bed, then proceeded to add a drop of water to the core surface, where it was observed that the drop was not absorbed by the core and the contact angle was greater than 90° [131]. Figure 6 presents a schematic representation of the experimental setup. At the top, it holds the prepared suspension (2) with an initial concentration (Ci) that flows downstream through the selected porous media (3) by gravitational forces. A filter paper (4) was used at the bottom of the assembly to collect the fines that migrate through the porous medium with the help of a vacuum pump (Cole–Parmer Instrument Co., Canada) (6). The filter paper was weighed each time that a pore volume of the fines suspension passed through the porous medium to determine the fines retained, using an analytical balance (OHAUS PionnerTM., USA) and hence obtain the resultant fines concentration (Ce). A normalized curve of concentration as a function of pore volume injected is constructed. The test was completed when Ci = Ce. The nanoparticles dosage was varied to estimate the optimum concentration, and for the nanoparticle with the best performance, a dosage of 1 wt% was used. Hence, the nanoparticle dosage was varied from 0.5, 0.01, 0.05, and 0.025 wt%. The concentration of the treatment adsorbed on the rock was determined from the gravimetric method with the effluent after applying the treatment. Likewise, the amount of fines retained in the sand-pack was determined from the differential weight. This difference was determined between the initial fines suspension and the fines in the filter paper after the suspension fines flow downstream through the sand-

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pack. The amount of fines not retained was calculated by the difference between the amount of fines retained and the total fines in the suspension. The migration and the retention capacity are percentage values of the amount of fines retained and not retained in the sand-pack.

Figure 6. Diagram of the displacement test: 1) the universal support, 2) the fines suspension, 3) the porous media, 4) the filter paper, 5) the Erlenmeyer, and 6) the vacuum pump.

4.2.2. Fines Retention Test: High Pressure The fines retention test was performed under reservoir conditions and was based on an evaluation of the critical rate. This property is defined as the maximum flow speed in which the fines in the formation remain attached to the surface and do not migrate [60, 119]. At higher rates than the critical velocity, a mechanical drag is induced which causes detachment of the fines and fines migration [60, 132]. Thus, it can cause

Inhibition of the Formation Damage due to Fines Migration … 259 plugging of the pore throats and decreased permeability [132]. Displacement tests to determine the critical rate are performed with a formation core from the oil field to establish the critical rate of fines migration. With these tests, the effectiveness of the nanoparticles was tested under typical reservoir conditions. The nanoparticles injection dosage was selected according to the fines retention tests. The test consists mainly of three steps. The first step is the construction of the base curves where their fundamental properties are measured. In the second stage, the critical rates are determined for conditions of effective permeability for oil and water In the third step, the critical velocity is evaluated after applying the treatment with the nanoparticles. The test conditions were: overburden pressure test was 5,000 psi, pore pressure of 2,500 psi, and temperature of 132°C. In the construction of the base curves, the samples were subjected to washing and drying procedures in 1:1 proportions of methanol/toluene. Then, the sample was saturated with brine by injecting water at a flow rate of 2 mL/min and the absolute permeability (Kabs) is measured. Afterward, the sample was progressed to Swr (residual water saturation) conditions injecting oil at a rate of 2 mL/min, and then the effective permeability to oil (Ko) was measured. Subsequently, the sample was carried to Sor (residual oil saturation) conditions to measure the effective permeability to water (Kw), injecting water at a rate of 2 mL/min. All these tests were performed under reservoir conditions of pressure and temperature. To determine the critical rate using the setup shown in Figure 7, the tests were performed at various pressure and temperature reservoir conditions. First, water was injected at a rate of 0.4 mL/min and K w was measured under Sor conditions. Then, water was injected at different flow rates increasing in intervals of 0.3 mL/min until detecting a decrease of at least 10% in the Kw. Subsequently, water was injected in the direction of injection to a critical flow to recover the permeability of the system. Water was then pumped into the normal direction at a rate of 0.2 mL/min and the Kw to Sor was measured to ensure that the permeability was recovered. Next, oil was injected at a flow rate of 0.2 mL/min and proceeds to measure the corresponding flow rates for Ko to Swr. Oil was injected at

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different rates starting from 0.4 mL/min and increasing each 0.3 mL/min until a decrease of at least 10% in Ko was observed. Then, oil was injected at the critical flow in the direction of the injection to recover the permeability system. Additionally, oil was injected in the normal direction at a flow rate of 0.2 mL/min, and Ko was measured again to Swr until the permeability was recovered.

Figure 7. Schematic representation of the critical rate test.

For the system in the presence of the nanoparticles, one pore volume of the stabilizing treatment was injected at a rate of 0.2 mL/min to stabilize the fine particles of the porous medium. The treatment was soaked for approximately 12 h. Posteriorly, the critical rate was determined by

Inhibition of the Formation Damage due to Fines Migration … 261 following the same procedure described for the system in the absence of the nanoparticles.

5. RESULTS 5.1. Methods 5.1.1. Fines Retention Test: Low Pressure Generally, the attractive forces are dominant between the interaction of the fines and the surface nanoparticles in the trapping of the fines [133]. The objective of the fines retention test is to determine the number of pore volumes in which the sand-pack is saturated of fines. A larger number of pore volumes, greater than the retention capacity of the nanofluid was injected. In Figure 8a, the behavior for water-wet beds is presented. For sand-pack without any impregnation, zero retention of the fines is observed. In the case of sand-pack impregnated with nanoparticles, these have a free effluent to the second fine-pore volume for PSN, which allows greater retention of the fines. In the case of sand-pack impregnated with SSN, the saturation occurs in the pore volume injected with No.10, a pore volume before the sand was impregnated with PSN. In this manner, the holding capacity of PSN is greater than SSN, caused possibly by the stronger attraction forces, such as VDW and the electrostatic forces [20, 26, 123, 125]. In Figure 8b, a similar trend to the previous sand-pack can be obesrved. The sand-pack with higher-retention capacity is the PSNimpregnated bed. In this case, there was no loss of nanoparticles, and 100% of the nanoparticles were retained on the surface of the sand. On the other hand, in the sand with damage, the bed allows the injection of a larger amount of pore volumes before the effluent starts out with a higher amount of fines. The results presented in Figure 8b are supported by the results of Ogolo et al. [129]. The reported results show that the presence of hydrocarbons in the sands has a positive influence on the performance of the nanoparticles.

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Figure 8. a) Inhibition curves for the fines migration in sand-pack without damage, b) Inhibition curves for the fines migration in sand-pack with damage.

Comparing the results previously reported for PSN, it can be observed that the degree of saturation for water-wet beds is established around 11 pore volumes, and for oil-wet beds is 10. Usually, the saturation time decreases with increasing bed height, with the particle size of the adsorbent, with the fluid flow through the bed, and the fines initial content in the solution. From the results of inhibition of fines migration curves in sand-packs with and without damage, the best performance is observed for the PSN nanoparticles. Therefore, Figure 9 indicates the PSN treatment evaluation at different concentrations of brine to determine the optimum concentration of the treatment. It can be inferred that the addition of the nanofluid generates an inhibition of fines migration. Increasing the nanoparticle concentration from 0 to 0.5 wt% improves the fine migration inhibition to concentrations above 0.5 wt% of the nanoparticles. It is expected that with the increase in the content of nanoparticles, plugging in the pore throats can be caused, or a decrease in the pore volume due to phenomena of attraction and aggregation by the charge difference between the nanoparticles and the fine clay migrants (quartz, illite, and kaolinite) present in the beds. The notably optimal concentration of nanoparticles for the control and inhibition of fine clay particles is 0.5 wt%, reaching adsorption equilibrium in the twelfth pore volume.

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Figure 9. a) Percentage gain curves of the sand beds (water-wet). b) Percentage gain curves of the sand beds (oil-wet).

The concentrations of 0.025, 0.05, and 0.1 wt% of the nanoparticles show improvement in reducing the fines migration. A proportional tendency is observed in the increase of the concentration of treatment with improved control and inhibition of the fines migration. At concentrations above 0.5 wt% of nanoparticles, it is observed that the treatment loses its effect in controlling the migration of the fine particles. Above this range, the nanoparticles saturate the bed, causing the drag of the treatment by the injected fine, which initiates the attraction and agglomeration phenomena. In the case of the breakthrough curve for the water-wet bed without any impregnation of nanoparticles, it is seen that the bed is saturated immediately, which describes the non-adsorptive and attraction phenomena between the sand and the fine migrants in the bed. Table 4 shows the results of evaluation of the water-wet beds at different concentrations. Comparing the amount of fines retained by the nanoparticles adhered to the sand bed (in weight percent), it is concluded that the amount of retained fines increases with the concentration of nanoparticles and the maximum control fines migration is achieved with a concentration of 0.5 wt% nanoparticles, resulting in improvements of up to 25%. To perform this comparison, the experiment was performed by flowing in the bed as many fines supported in all tests, i.e., a volume of 384 mL, equivalent to 0.85 g of fine particles.

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Concentration treatment (wt%) Concentration treatment adsorbed on the rock (wt%) Amount of fines retained (g) Amount of fines unretained (g) Retention capacity (%) Migration (%)

Blank

0.025

0.05

0.1

0.5

1

Blank

0.018

0.035

0.070

0.350

0.700

0.03

0.080

0.090

0.110

0.210

0.170

0.82

0.770

0.760

0.740

0.640

0.680

3.53

9.410

10.59

12.94

24.71

20

96.47

90.590

89.410

87.060

75.290

80

In Figure 9b, the breakthrough curves at equilibrium for the beds of oil-wet sand are shown. It can be seen that the interaction of the nanoparticles with the fine clay particles promote the control and inhibition of the fines migration in the oil-wet beds. It can be concluded that the concentration of 0.5 wt% of nanoparticles in the brine shows the best performance because it serves as an inhibitor of the fines migration. In this case, the saturation of the bed was 11 pore volumes, while the other concentrations reached equilibrium between the third and tenth pore volumes. The breakthrough curve of oil-wet sand without treatment shows the same behavior as the water-wet bed without treatment, both arriving immediately at the saturation level. The differences between the values of wettability indicate that for the oil-wet bed, the flow is higher because the bed is hydrophobic and water flows more easily. This event generates a shorter interaction between the nanoparticles adhered to the bed and the fine flow, decreasing the adsorptive activity of the nanoparticles. In the water-wet bed, the water affinity has a lower effect, which causes the fines flow to have greater interaction with the nanoparticles, having a positive effect on the fine particles retention.

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Figure 10. Comparison of the results of injected volumes of fine as a function of the weight concentration of the nanoparticles for oil- and water-wet beds.

Comparing Figures 9a and 9b, it can be observed that the best performance is achieved for 0.5 wt% concentration of nanoparticles and at concentrations greater or equal to 1 wt% nanoparticles, the treatment is no longer effective for the control and inhibition of the fine particles, as shown in Figure 10. Table 5. Results for oil-wet beds Concentration treatment (wt%) Concentration treatment adsorbed on the rock (wt%) Amount of fines retained (g) Amount of fines unretained (g) Retention capacity (%) Migration (%)

Blank

0.025

0.05

0.1

0.5

1

Blank

0.02

0.04

0.08

0.4

0.8

0

0.0064

0.0624

0.0524

0.1029

0.0852

0.77

0.77

0.71

0.72

0.67

0.69

0

0.87

8.1

6.81

13.36

11.06

100

99.13

91.9

93.19

86.64

88.94

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Figure 10 shows a high affinity for the treatment of water-wet beds, where a higher retention of the fine particles and better fines migration control are evident. It can be observed that for lower concentrations or greater than 0.5%, the conditions for the control and inhibition of the fines migration (kaolinite, illite, and quartz) in oil- and water-wet beds are not favorable. Table 5 shows the results of the evaluation of oil-wet treatment beds at different concentrations. Unlike the behavior of water-wet beds, in this case, to assess the concentration of 0.5 wt% of nanoparticles, it presented a retention of 13%. The decrease of holding capacity is 12%, due to the differences between the values of wettability and alterations in the porous medium.

5.1.2. Estimation of the Critical Rate of the Fines Migration To evaluate the wettable nature of the fines, the hurdle rate is determined when the brine flows into the core clean. When these findings are compared with those obtained in the Sor, it can be determined if the presence of the oil affects the mobility of the fine particles. Figure 11 shows that at a flow rate of 1.5 mL/min, the permeability of the system is reduced. The critical rate is the last rate at which the system does not present a drop in permeability, caused by the mobilization of the fines. In this case, the critical rate is 1.2 mL/min to brine flow. To determine the effectiveness of the treatment, critical rates are analyzed in oil and water flow conditions. In the first case, before treatment, it is determined that the drop in permeability was 46% when the rate increased from 0.7 to 1 mL/min; and after treatment, a drop of 43% after increasing the the rate of injection from 1.5 to 1.8 mL/min. In both flow environments, the treatment is effective in stabilizing the fine particles, increasing the crica rate in both phases. In the oil case, it is possible to improve the critical rate by a factor of 2.14, and in the water case, it is feasible to improve the critical rate 2.8 times. Figures 12 and 13 contrast the critical rates in the water and oil phases, before and after treatment, respectively.

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Figure 11. Critical rate–absolute permeability.

Figure 12. Critical rate to oil— before (green box) and after treatment (blue box).

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Figure 13. Critical rate to water— before (green box) and after treatment (blue box).

Therefore, from the displacements made before the treatment, two important features can be observed. The first is that the water critical rate is much higher than that of the oil, and the second is that the presence of oil in the medium favors the stabilization of the fine particles. This is concluded from the analysis of the critical rates without Sor (1.2 mL/min), which is lower than the water flow (1.8 mL/min).

5.1.3. Field Trial The field trial was performed in the CWA well located in determined field in Colombia. The reservoir fluid is condensated gas with a gradient of 0.2 psi/ft. This well was completed in September 2009 with a perforation of 34.1 m for the BC formation (4,653.7 m–4,681.7 m), the fracturing of the formation of GP and the perforating of the intervals Q and L of the formation of GP. The characteristics of the formation are presented in Table 5.

Inhibition of the Formation Damage due to Fines Migration … 269 Table 5. Formation characteristics of the CWA well Formation BC GP Q GP L

Thickness (ft) 194.5 135.5 126.5

Permeability (mD-ft) 445 960 581

Pressure (psia) 4020 4034 4100

Figure 14. Results of pilot test for: a) oil and water, and b) gas.

Temperature (°C) 132 280 282

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The silica-based nanofluid provided excellent results. The pilot consisted of three stages. The first involved the cleaning of the pipes; then a matricial chemical stimulation is used for the organic and fine components of the BC formation. Subsequently, the inhibition test and fines stabilization was performed with the nanofluid, where 148 bbls of nanofluid were pumped. The production increased in the first two days of nanofluid application. The increase of 48 bbl of oil compared to the baseline and the increase of 134 bbl relative to the previous treatment stage, show the optimum behavior of the nanoparticles. The production of gas increases 1,000 Kscfd compared to the baseline. This demonstrated the effectiveness of the treatment in the retention and adsorption of fine particles in the BC formation. On the other hand, the production of water exhibited no significant change from the baseline but presented a decrease of 40% compared to post-pickling. Figure 14 presents the results presented in the pilot test for the production of oil, water, and gas.

CONCLUSION From the tests and field trials, it is possible to determine that fines migration inhibition is favored using nanoparticles, which create a bridge of electrostatic forces between the fine particles and the bed, favoring attractive forces. In the fines retention test, PSN has a better performance with higher-retention capacity obtained in the beds. In the critical rate test, the fine particles show a tendency to be oil-wet, which is reflected in a lower critical rate for water in the presence of oil residual saturation and a higher critical rate for the water flow compared to oil. Similarly, in the test using nanoparticles, the critical rate values are twice the original system critical speed. This result validates the effectiveness of the proposed technology as a stabilizing agent of fine particles. Besides, the pilot test presented excellent results in the production of oil and gas after the nanofluid treatment was applied and a decreased production of water around of 40%.

Inhibition of the Formation Damage due to Fines Migration … 271

ACKNOWLEDGMENTS The authors are grateful to Ecopetrol S.A, COLCIENCIAS and Universidad Nacional de Colombia for logistical and financial support.

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In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 7

APPLICATION OF NANOFLUIDS FOR IMPROVING OIL MOBILITY IN HEAVY OIL AND EXTRA-HEAVY OIL: A FIELD TEST Richard D. Zabala1, Camilo A. Franco 2 and Farid B. Cortés2,* 1

Gerencia de Desarrollo de Yacimientos, Vicepresidencia Técnica de Desarrollo, Bogotá, Colombia 2 Grupo de Investigación en Fenómenos de Superficie–Michael Polanyi, Departamento de Procesos y Energía, Facultad de Minas, Universidad Nacional de Colombia, Sede–Medellín, Colombia

ABSTRACT An important factor during the life of a heavy crude oil reservoir is oil mobility. Oil mobility depends on two factors: oil viscosity and oil relative permeability. Two nanoparticle characteristics can make them *

Corresponding Author Email: [email protected].

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Richard D. Zabala, Camilo A. Franco and Farid B. Cortés attractive for assisting IOR and EOR processes: their size (1 – 100 nm) and their ability to manipulate the behavior of IOR and EOR processes. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the particle surface, indicating an increase in surface energy. Nanoparticles are also able to flow through common reservoir pore spaces with sizes of, or below, 1 micron without the risk of blocking the pore space. Nanofluids, or “smart fluids,” can be designed by tuning nanoparticle properties and are prepared by adding small concentrations of nanoparticles to the liquid phase to enhance or improve some of the fluid properties. However, the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present a field evaluation of nanofluids for improving oil mobility and mitigate wettability alterations in two Colombian heavy oil fields: CA and CH. Asphaltene sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil-based nanofluid (OBN) containing these nanoparticles was evaluated as a viscosity reducer under static conditions. Displacement tests through a porous media in core plugs under reservoir conditions were also performed at CA and CH. The OBN was evaluated for its ability to reduce oil viscosity under various oil temperature and water content conditions. The maximum change in oil viscosity was achieved at 122°F with 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests (caused by the removal of asphaltenes from the aggregation system), reduced oil viscosity, and effectively restored the original core wettability. Two field trials were performed in CA (CN1 and CN2 wells), by forcing 200 bbl and 150 bbl of nanofluid, respectively, as the main treatment within a ~ 3 ft penetration radius. Instantaneous oil rate increases of 270 bopd in CN1 and 280 bopd in CN2, and BSW reductions of ~ 11% were observed. In CH, two trials were also performed (CH1 and CH2) by forcing 86 bbl and 107 bbl of nanofluid, respectively, as main treatment within a ~ 3 ft penetration radius. Instantaneous oil rate increases of 310 bopd in CH1 and 87 bopd in CH2 were achieved; however, BSW reduction has yet to be observed. The interventions were performed a few months ago, and the long-term effects are still under evaluation. Nevertheless, the results look promising and encourage extension of this nanofluid application to other wells in these fields.

Keywords: nanofluid, nanoparticle, heavy oil, field trial, viscosity, mobility

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1. INTRODUCTION An important factor during the life of a heavy crude oil reservoir is oil mobility. Oil mobility depends on two factors: oil viscosity and oil relative permeability [1, 2]. Two nanoparticle characteristics make them attractive for assisting IOR and EOR processes: their size (diameter ranging from 1 to 100 nm) and their ability to manipulate the behavior of IOR and EOR processes [3-5]. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the particle surface, indicating an increase in surface energy. Nanoparticles are also able to flow through common reservoir pore spaces with sizes of, or below, 1 micron without the risk of blocking the pore space [6]. Nanofluids, or “smart fluids,” can be designed by tuning nanoparticle properties and are prepared by adding small concentrations of nanoparticles to the liquid phase to enhance or improve some of the fluid properties [7, 8]. However, the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hamedi et al. [9], studied the effect of micro-sized (iron and copper) and nano-sized (iron and nickel) metal particles for heavy oil viscosity reduction. Viscosity reduction tests were performed by adding 0.1, 0.5, and 1 wt% of the material to heavy oil (14.7 API) at 77, 122, and 176°F using an AR-G2 rotational rheometer. The authors found that, in general, the highest reduction was achieved by adding 0.1 wt% of the particles. However, the percentage of viscosity reduction was not higher than 9.5%, which was obtained from adding 0.1 wt% of micro-sized copper particles. Recently, some researchers have suggested that the mobility and effectiveness of wettability modifiers, such as surfactants, can be increased by the addition of nanoparticles [1, 2, 10-13]. Karimi et al. [12] studied the effect of zirconium oxide (ZrO2)-based nanofluids on the wettability alteration of a carbonate rock reservoir. Several nanofluids composed of ZrO2 nanoparticles and mixtures of nonionic surfactants with a hydrophilic-lipophilic balance ranging from 15 to 1.8 were made. Two different nanoparticle concentrations were tested (50000 and 100000 mg/L). Free imbibition tests evaluated the impact of wettability alteration

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on oil recovery and the authors concluded that the designed ZrO2-based nanofluids were effective wettability modifiers for carbonate systems since they could change the rock wettability from a strongly oil-wet to a strongly water-wet condition. In another study, Giraldo et al. [2] studied the effectiveness of alumina-based nanofluids in altering the wettability of sandstone cores with an induced oil-wet wettability. They used five nanofluids with different particle concentrations ranging from 100 mg/L to 10000 mg/L that were prepared by dispersing the alumina nanoparticles in a commercial surfactant. By contact angle and imbibition tests, they showed that the designed nanofluids could alter the rock wettability significantly from a strongly oil-wet to a strongly water-wet condition. Imbibition tests also allowed identification of the nanoparticles concentration effect on the suitability of the treatment for enhancing the imbibition process and restoring the original core wettability. The best performance was achieved when a concentration of 100 mg/L was used. They also performed a core displacement test by injecting the alumina-based nanofluid in a sand pack. The treatment was effective in altering the sand pack wettability from an oil-wet to a strongly water-wet condition. Franco et al. [1] analyzed the effect of the chemical nature of twelve types of nanoparticles on asphaltenes adsorption and the deposition delay, or inhibition, of asphaltenic compounds precipitation under reservoir conditions. Nanoparticles that favored Langmuir-type isotherms were found to be good candidates for inhibiting asphaltene precipitation onto the rock surface. Only nanoparticles that strongly adsorbed the more polar compounds were capable of neutralizing the polar forces that remained active during weak adsorption to cause multi-layer adsorption. Asphaltene precipitation inhibition prevents flocculation-precipitation, which these polar compounds seem to be composed from, and eliminates the tendency of asphaltenes toward multi-layer adsorption, which could be due to the remaining polarity of the initially adsorbed asphaltenes. The injection of nanofluids into the porous media showed agglomeration, precipitation, and deposition of asphaltenes onto the rock surfaces was inhibited. This observation was based on a three-step displacement test. Additionally, the

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nanoparticle treatment demonstrated an enhanced perdurability of the system. The nanoparticles were able to restore production and led to improvements in recovery due to their ability to adsorb and stabilize the asphaltenes content of the system. Zabala et al. [5] analyzed the effect of two nanoparticles on the adsorption of asphaltenes extracted from two Colombian heavy oils fields: CA and CH. This study was designed to select the best nanomaterial for enhancing oil-based nanofluids that can restore the wettability of cores from oil-wet to water-wet and increase the oil mobility through the porous media under reservoir conditions. The use of the nanofluids increased oil recovery in the core flooding tests (caused by asphaltenes inhibition), reduction of oil viscosity, and effectively restored the original core wettability. This chapter describes the recent journey into studying two fields in Colombia with a novel technique based on oil-based nanofluids carrying the tailor made nanomaterials according to the previous scenario. Two nanofluid injection jobs were performed in the CA field and two jobs in the CH field. The nanotechnology was successfully implemented. The CA heavy oil field is located in Colombia’s Llanos basin. This field was discovered by Chevron in 1969; but it has been operated upon by Ecopetrol S.A since 2002. There are three operating areas, called CA, CA Norte, and CA Este. However, the geology, stratigraphy, and reservoir units are the same. The structural interpretations confirm that the CA field is formed by a north-east (NE) to south-west (SW) trending asymmetric anticline that forms a three-way dip closure against the CA fault complex to the SE. The main producing stratigraphic units are K2, and K1, which has been split into two subdivisions: the upper (K1 Superior) and lower (K1 Inferior). There is an additional tertiary stratigraphic unit called T2; but, it is currently a secondary target. The petrophysical properties of the CA field are fairly good: porosity varies from 16% to 22%, permeability ranges from 500 to 10000 mD, initial water saturation is around 15%, API gravity is around 13°, and the oil viscosity is close to 150 cP. On the other hand, the Free Water Level is tilted and saturated with fresh water (active strong aquifer). The CH heavy oil field is located near the CA field. This field was discovered by Chevron in 1969, but it has been operated upon by

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Ecopetrol S.A since 2000. The structural interpretations confirm that the CH field is formed by a NE-SW trending asymmetric anticline bounded by a reverse fault complex to the east and southeast. The main producing stratigraphic units are T2, and K1. The petrophysical properties of the CH field are fairly good: porosity varies from 16% to 20%, permeability ranges from 800 to 4000 mD, initial water saturation is around 22%, API gravity is around 8°, and oil viscosity is close to 350 cP.

2. EXPERIMENTAL 2.1. Materials 2.1.1. Crude Oils The “CH” (8° API at 77°F, 1% water content, and 16% by weight of asphaltenes) and “CA” (12° API at 77°F, 25% water content, and 8% by weight of asphaltenes) crude oils were used to evaluate the development of the nanofluid in a porous media. The crude oils were also used as a source of asphaltenes. In this document, the “CH” and “CA” crude oils are named “CHO” and “CAO,” respectively. 2.1.2. Solvents and Reagents For asphaltenes extraction from the crude oils, n-heptane (99%) was used. Toluene (99%) was used to dissolve the asphaltenes and dilute to the desired concentration. Nanoparticles A (NPA) and nanoparticles B (NPB), supplied by Petroraza (Colombia), were used to perform the asphaltenes adsorption experiments. Commercial nanoparticles C (NPC), nanoparticles D (NPD), and nanoparticles E (NPE) were also used to perform the adsorption tests. Commercial oil-based nanofluid (OBN, 15° API; viscosity, 8.14 cP, and pH 10.23 at 76.3°F) and commercial pre-flux were used to perform the displacement tests.

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2.2. Methods 2.2.1. Asphaltene Extraction Protocol Asphaltenes were precipitated from CHO and CAO following a standard procedure [3, 6, 14]. The model solutions for the batch adsorption experiments were prepared by dissolving the desired amount of the obtained asphaltenes in toluene. The initial concentration of the asphaltene solutions used in the adsorption experiments ranged from 250 to 1500 mg/L. 2.2.2. Surface Area and Particle Size Measurements The surface areas (SBET) of the prepared nanoparticles were estimated following the Brunauer–Emmett–Teller (BET) method [15]. The mean crystallite size of the particles (dp: nanoparticle diameter) was obtained by applying the Scherrer equation to the main diffraction peak. 2.2.3. Equilibrium Adsorption Isotherms According to the procedure described in previous studies, the amount of asphaltenes adsorbed (mg of asphaltenes/g of nanoparticles) was determined by the mass balance in Eq. 1 [3, 6, 14]: 𝑁𝑎𝑑𝑠 =

𝐶0 −𝐶𝐸 𝑉 𝑊

(1)

where 𝐶0 is the initial concentration of asphaltenes in the solution (mg/L), 𝐶𝐸 is the equilibrium concentration of asphaltenes in the supernatant (mg/L), 𝑉 is the solution volume (L), and 𝑊 is the amount of nanoparticles added to the solution (g).

2.2.4. Viscosity Measurements The Fungilab rotational viscometer Smart R was used to perform the viscosity measurements at 86, 122, and 175°F for CHO and 86, 122, and 156°F for CAO. First, the base curves without treatment were constructed.

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Then, 0.5, 1, 2, and 3 wt% of nanofluid were added and the viscosity measurements were performed.

2.3. Fluid Injection Tests 2.3.1. Porous Media Two cores were used to study the transport behavior of the nanofluid through the porous media. For CHO, the selected core was “CHI 30– 7920.5.” The porous media has an absolute permeability of 622 mD, a porosity of 21%, diameter of 3.75 cm, and length of 7.00 cm. For CAO, the selected core was “CA N0046 – 7432.5.” In this case, the plug has an absolute permeability of 500 mD, a porosity of 11%, diameter of 3.80 cm, and length of 6.75 cm. 2.3.2. Preparation of the Injection Fluids For the fluid injection test, two synthetic brines were prepared for each field to get an accurate approximation of the reservoir conditions. The nanofluid was magnetically stirred at 77°F for 6 h and then sonicated at the same temperature for 24 h such that the nanoparticles remained stable in the suspension. According to the results of the adsorption isotherms, NPA was used in the displacement test. 2.3.3. Experimental Setup and Procedure Figure 3 shows a schematic representation of the experimental setup. For CHO, all tests were carried out at a temperature of 210°F with a pore pressure of 3002 psi. For CAO, the test temperature was 188°F and the pore pressure and overburden pressure were 2495 and 3002 psi, respectively. For the displacement tests on the porous media, the chemical nature of the nanoparticles and their concentration in the aqueous solution were selected based on the isotherm results. The main objective of this displacement test was to evaluate the effectiveness of the nanoparticles at

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Figure 3. Schematic representation of the experimental setup. Legend: (1) core holder, (2) sand packed bed, (3) displacement cylinder, (4) positive displacement pump, (5) mineral oil pump, (6) pressure transducers, (7) valves, and (8) sample output.

improving the oil mobility and changing the core wettability to a water-wet medium from an oil-wet system. The displacement tests were carried in four steps: 1) Constructing the initial curves. 10 pore volumes (PV) of water were injected to measure the absolute permeability at the temperature, pore pressure, and overburden pressure desired. Then, at the same temperature and under the saturation condition of residual water (Swr), the crude oil was injected until the pressure no longer changed. Finally, 20 PV of water was injected at the test temperature to construct the relative permeability curves as functions of water saturation. Accordingly, the recovery curves (Np) and the effective permeability to water at the saturation of oil residual (Sor) conditions were measured. 2) Creating an oil-wet core medium and constructing the base curves. First, the core was saturated by injecting 20 PV of crude oil and aged for 10 days, injecting 1 PV of crude oil each day. Then, for verifying if the system was oil wettable, the base curves were constructed following the same procedure

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as for the initial curves. 3) Evaluating the OBN in terms of crude oil mobility and wettability restoration. 10 PV of crude oil was injected to saturate the porous media. At that point, 0.3 PV of pre-flux were injected to condition the porous media for nanofluid injection. Then, the core was aged with the nanofluid for 4 h by injecting 0.3 PV of the nanofluid. After that, pressure changes were verified to evaluate improvements in the oil mobility. Changes in the core wettability were verified by injecting 20 PV of crude oil in the production direction (i.e., closing both inlet and outlet valves, unplugging the core holder, and twisting it horizontally to plug the input valve with the core holder outlet). Then, 20 PV of water was injected to measure the relative permeability and Np curve. 4) Observing the perdurability of the nanofluid treatment on the porous media. Crude oil was injected into the porous media until the Ko was approximately equal to the base Ko.

3. RESULTS AND DISCUSSION 3.1. Nanoparticle Characterization Table 1 presents the evaluated properties of the nanoparticles. Table 1 shows that NPA have a larger surface area and particle diameter than NPB. Based on the measurement of N2 adsorption, NPA has a surface area of 223.2 m2/g and NPB of 119.1 m2/g. The dp of NPA and NPB were 35 nm and 7 nm, respectively. Table 1. Estimated dp values and surface area of the selected nanoparticles Material NPA NPB NPC NPD NPE

dp (nm) 25 7 28 15 19

Surface area (m2/g) 223 120 102 99 103

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3.2. Batch Adsorption Test: The Equilibrium Isotherm of Asphaltenes Adsorption onto the Nanoparticles Figure 4 presents the maximum adsorption capacities of asphaltenes extracted from CHO and CAO onto NPA, NPB, NPC, NPD, and NPE at 77°F. For all of the materials evaluated, the adsorptive capacity was higher for CHO, and NPA and NPB showed higher adsorption capacities than the other nanoparticles. Figure 5 shows the experimental adsorption isotherms at 77°F versus the calculated adsorption isotherms at: a) 210°F for CHO and b) 188°F for CAO. As seen, the asphaltenes extracted from CHO showed more adsorption affinity toward NPA and NPB. That is, the NPA and NPB samples adsorbed more asphaltenes from CHO than from CAO. This observation can be attributed to the intermolecular forces (i.e., the polar interactions and coulombic forces between the localized charges, which resulted from either permanent or induced dipoles) between the most polar components of the asphaltene molecules from CHO (lower API gravity than CAO) and the surfaces of the nanoparticles. As a comparison, for a concentration of 281 mg/L, NPA adsorbed 121 mg of asphaltenes extracted from CHO per gram of nanoparticles while at the same concentration, the asphaltenes adsorbed from CAO were 107 mg/g. For NPB, there was less difference between the amounts of asphaltenes adsorbed. For the adsorption of asphaltenes extracted from CHO, the amount adsorbed was 64 mg/g at a concentration of 780 mg/L; and for the asphaltenes extracted from CAO, the amount was 61 mg/g at the same concentration. In Figure 5, it can also be observed that NPA has a higher uptake than NPB for both CHO and CAO. This can be attributed to the SBET value of NPA, which is 46% higher than the SBET of NPB. While NPA captured 121 mg/g of asphaltenes extracted from CHO at a concentration of 281 mg/L, NPB captured approximately 62 mg/g at the same concentration. For CAO, a similar trend was observed. While the amount adsorbed at 280 mg/L for NPA was 106 mg/g, for NPB, this was 58 mg/g. As expected, the amount of asphaltenes adsorbed decreased as the temperature increased for both CHO and CAO due the exothermic behavior of the process. Temperature is

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strongly related to the size of the asphaltene aggregates. As the temperature increases, the aggregate size decreases, and the adsorption capacity decreases. [39] It can be seen in Figure 7a that the amount of asphaltenes extracted from CHO onto NPA at the reference concentration of 281 mg/L decreased from 121 to 80 mg/g; and for NPB, at a concentration of 780 mg/L, the amount of asphaltenes extracted decreased from 64 to 49 mg/g. In the case of the asphaltenes extracted from CAO (Figure 7b), the amount adsorbed onto NPA changed from 113 to 100 mg/g at 364 mg/L; and for NPB, the amount adsorbed changed from 61 to 44 mg/g at 800 mg/L.

Figure 4. Experimental data for maximum adsorptive capacities of CHO and CAO asphaltenes onto NPA, NPB, NPC, NPD, and NPE at 77°F. Adsorbent dose, 10 mg/ml; shaking rate, 300 rpm.

Figure 5. Experimental data of asphaltenes adsorption isotherms for NPA and NPB at 77°F and the calculated isotherms for a) CHO and b) CAO with reservoir temperatures of 210°F and 188°F, respectively.

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3.3. Viscosity Measurements Figure 6a shows the effects of the OBN on the CHO viscosity at 86, 122, and 175°F. The viscosity decreases between 75% and 99% for all of the temperatures studied. Figure 6b shows the curves of viscosity reduction for CAO at 86, 122, and 156°F; the viscosity decreases between 97% and 99.9%.

Figure 6. a) Viscosity of CHO as a function of the treatment dosage at 86 (), 122 (), and 175°F (△).b) Viscosity of CAO as a function of the treatment dosage at 86 (), 122 (), and 156°F (o).

3.4. Core Displacement Tests According to the batch adsorption test results, NPA was used in the displacement test. For each crude oil type, a core displacement was carried out by injecting the OBN under the respective reservoir conditions. Three scenarios were evaluated: 1) initial conditions (washed core), 2) base case scenario (core aged 10 days with crude oil), and 3) scenario after nanofluid injection. For CHO, the Sor decreased to 52% from scenario 2 to scenario 3 while the Kro increased to 358% (Figure 7a). On the other hand, for CAO, the Sor decreased to 57% from scenario 2 to scenario 3 while the Kro increased to 199% (Figure 7b). The use of the OBN increased hydrocarbon flow successfully because the asphaltene adsorption onto the

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rock surface was inhibited, a critical reduction in oil viscosity was effected, and the original core wettability was effectively restored.

4. FIELD APPLICATION Formation damage models were developed for the CA and CH fields. Figure 8 shows the most important sources of damage present in these areas. In CH, induced damage, emulsion damage, and problems in the relative permeability curves (Krs) were the most important sources of damage with relative weightings of 29, 31.9, and 37%, respectively (Figure 8a). Other sources of damage, such as mineral and organic scales, were present in lower proportions. In CA, the damage was produced by organic scales due to the precipitation of asphaltenes (30%) and mineral scales (14%). However, the main source of damage was induced during drilling, cementing, and completion operations (56%) (Figure 8b). The objective of the stimulation process with the OBN in these fields is to mitigate the sources of damage associated with organic deposits, emulsions, and problems in the Krs, the actual main sources of damage. For the trials, a candidate selection process was implemented resulting in the selection of CH1 and CH2 wells in CH and CN1 and CN2 wells in CA for the pilot projects.

Figure 7. The relative permeability curves for the initial, base,, and treated systems in plugs saturated with a) CHO and b) CAO.

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Figure 8. Distribution of damage formation origins in a) CH and b) CA.

4.1. CH Field Results In CH, the intervention jobs were designed within a treatment radius of ~3 ft, squeezing 86 bbl and 107 bbl of nanofluid as the main treatment in CH1 and CH2, respectively. Other stages in the well program were included. In order to remove the organic deposits, an organic treatment was used followed by a step to remove calcite with a scale dissolver. The nanofluid and other fluids were pumped at matricial low rate and then wells were shut down for 12 h of soaking. After the interventions, the production of the wells showed instantaneous oil rate increases of around 310 bopd in CH1 and 87 bopd in CH2; however, BSW reductions were not observed. As an example, the complete results from CH1 are presented in this paper. CH1 represents a well with typical formation damage from the field (Figure 8a). Determination of skin damage with nodal analysis before and after the nanofluid treatment shows a change of the skin from 23 to 6.2, as shown in Figure 9a. This 73% reduction of skin damage represents an instantaneous oil rate increase to 310 bopd. The production gain was monitored until the 269th after well treatment, and the oil production rate still exceeds the base line rate (Figure 9b). According to the results, nanofluid injection appears to be an efficient treatment. It is worth mentioning that the capital invested in the stimulation operation was recovered within the first three months, and the following months represent economic benefits. As soon as the well was opened for

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production, the first observation was the reduction in the crude oil viscosity and improvements in oil mobility. Well performance coincides with the reduction in viscosity of the oil produced during the first 120 days (Figure 10a). Thereafter, oil viscosity measurements reached base line conditions. In the first 9 days, viscosity reductions of around 98% were observed. It is important to remember that the nanofluid was pumped into the media only once, not a continuous injection. The results are shown in Figure 10b. Due to the high polarity of the employed nanoparticles, tracking of residual nanoparticles was performed by measuring the content of nanoparticles in the production water. For samples without free water, lixiviation with distilled water was performed to obtain an aqueous sample for residual nanoparticles measurements. The residual concentration of nanoparticles after 269 days was 56 ppm (Figure 10b). This value indicates that the effective treatment lifetime is longer than 269 days.

4.2. Ca Field Results Stimulation jobs in CA were designed within a penetration radius of ~3 ft, 200 bbl and 150 bbl of nanofluid were pumped as the main treatment in CN1 and CN2 respectively. In CN1, other stages in the well program were included. To remove organic deposits, an organic treatment was used followed by a step to remove calcite with a scale dissolver. In CN2, only the nanofluid was injected. The nanofluid and other fluids were pumped at matricial low rate and then the wells were shut down for 12–18 h of soaking. Instantaneous oil rate increases of 270 bopd in CN1 and 280 bopd in CN2 were observed along with BSW reductions of ~ 11%. The results from well CN1 are presented in this paper. Formation damage distribution described for CA field (Figure 8b) was fulfilled in the CN1 well. Determination of skin damage with nodal analysis before and after the nanofluid treatment shows a change from 47 to 19, as shown in Figure 11a. This 60% reduction in skin damage represents an instantaneous oil rate increase to 270 bopd.

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Figure 9. a) Skin before and after the treatment: i) Before treatment, 263 BFPD, 5.65% BSW, 248 BOPD, and Pwf = 1303 psi; ii) After treatment, 641 BFPD, 12.95% BSW, 558 BOPD, Pwf = 1278 psi, and ∆Qo = 310. b) Production increases.

Figure 10. a) Viscosity of the produced fluids from well CH1 and b) residual of nanoparticles.

Production gains extended until day 174. Thereafter, the well reached base line levels (Figure 11b). According to results, this appears to be an effective treatment; however, the results from CH were better. It is noteworthy that the capital invested in the treatment operation was recovered after four months. As soon as the well was opened for production, the reduction in crude oil viscosity and improvement in oil mobility were immediately observed. BSW reduction effects were also noted, about 11% points less than before the treatment. This is because the

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system becomes strongly water-wet. Effects in BSW reduction, viscosity reduction, and improvement in oil mobility were noted by almost the same 174 days that maintenance for residual nanoparticles was recorded in the well. The results are shown in Figure 12. The residual concentration of nanoparticles after 200 days was negligible (Figure 12b). In the first 30 days, viscosity reductions of around 47% were observed.

Figure 11. a) Skin before and after nanofluid treatment: i) Before injection, 201 BFPD, BSW 20%, 160 BOPD, and Pfw = 1280 psi; ii) Post injection 485 BFPD, BSW 9.67%, 438 BOPD, Pfw = 938, and ∆Qo = 278. b) Production increases.

Figure 12. a) Viscosity of the produced fluids for well CN1 and b) residual of nanoparticles.

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CONCLUSION 













The experimental results showed that nanoparticles A (NPA) lead to a higher asphaltenes uptake than nanoparticles B (NPB) for both CHO and CAO. The treatment based on NPA was effective for reducing the CHO and CAO viscosities. A new protocol, at the laboratory scale, was implemented to evaluate the nanofluid behavior in the porous media under reservoir temperature and pressures. The injection of nanofluids into the porous media showed that the nanoparticles can restore rock wettability from an oil-wet to water-wet state and increase the oil mobility. The nanoparticles also were able to restore production and led to improvements in the oil recovery percentage due to their ability to change the wettability of the core. Formation damage models were developed and they identified that the CA and CH fields were good candidates for the use of a nanoparticles-based treatment. A candidate selection process was implemented. In CH, wells CH1 and CH2 were selected as the pilots. In CA, wells CN1 and CN2 were selected as the pilots. The Main sources of formation damage in these fields were associated with organic deposits, emulsions, and problems in the relative permeability curves. The objective of the stimulation process with the OBN was to mitigate these mechanisms. In CH, field interventions showed instantaneous oil rate increases of around 310 bopd in CH1 and 87 bopd in CH2; however, BSW reductions were not observed. The nodal analysis in CH1, before and after the nanofluid treatment, showed a change in the skin from 23 to 6.2. This represents a reduction in the skin damage of about 73%. In the first 9 days, viscosity reductions of around 98% were observed. It is important to note that the nanofluid was pumped into the formation only once and that this is not a continuous injection. Production benefits from the stimulation treatment were observed up to the 269th day after the well was treated. Currently, the oil rate

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





 

is still above the base line rate. The residual concentration of nanoparticles after 269 days was 56 ppm. This value indicates that the effective treatment lifetime is longer than 269 days. Stimulation treatment in the CA field showed instantaneous oil rate increases of 270 bopd in CN1 and 280 bopd in CN2 with BSW reductions of ~ 11%. The nodal analysis in CN1, before and after the nanofluid treatment, showed a decrease in the skin damage of about 73% (skin from 47 to 19). In the first 30 days, a viscosity reduction of around 47% was observed. Positive results from CN1 finished 174 days after the well was treated. The residual concentration of nanoparticles after 200 days was negligible. Positive results in the CH field lasted longer than in the CA field. This could be because the CHO is heavier than CAO. The Final results are still under evaluation, but results are promising (BSW reduction in CA has been confirmed). It is now possible to extend this nanofluid application to other wells in these fields.

ACKNOWLEDGMENTS The authors would like to thank Ecopetrol for granting permission to present and publish this chapter. The authors acknowledge Universidad Nacional de Colombia for logistical and financial support.

REFERENCES [1]

Franco, CA; Nashaat, N. Nassar; Marco, A. Ruiz; Pedro, PereiraAlmao; Farid, B. Cortés. Nanoparticles for inhibition of asphaltenes

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[2]

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damage: adsorption study and displacement test on porous media. Energy & Fuels, 2013, 27(6), p. 2899-2907. Giraldo, J; Pedro, Benjumea; Sergio, Lopera; Farid, B. Cortés; Marco, A. Ruiz. Wettability alteration of sandstone cores by aluminabased nanofluids. Energy & Fuels, 2013, 27(7), p. 3659-3665. Franco, CA; Nashaat, N Nassar; Tatiana, Montoya; Farid, B. Cortés. NiO and PdO Supported on Fumed Silica Nanoparticles for Adsorption and Catalytic Steam Gasification of Colombian C7 Asphaltenes, in Handbook on Oil Production Research, J. Ambrosio, Editor., 2014, Nova Science Publishers., p. 101-146. Franco, CA; Monica, M. Lozano; Socrates, A. Acevedo; Nashaat, N. Nassar; Farid, B. Cortés. Effects of Resin I on Asphaltene Adsorption onto Nanoparticles: A novel method for obtaining Asphaltenes/Resins Isotherms. Energy & Fuels, 2016, 30(1), p. 264272. Zabala, R; Mora, E; Botero, OF; Cespedes, C; Guarin, L; Camilo, A. Franco; Farid, B. Cortes; Edgar, Patino; Natalia, Ospina. NanoTechnology for Asphaltenes Inhibition in Cupiagua South Wells., in International Petroleum Technology Conference, 2014. Franco, CA; Edgar, Patiño; Pedro, Benjumea; Marco, A. Ruiz; Farid, B. Cortés. Kinetic and thermodynamic equilibrium of asphaltenes sorption onto nanoparticles of nickel oxide supported on nanoparticulated alumina. Fuel, 2013, 105, p. 408-414. Sherik, AMaKMN. Applications of nanotechnology in oil and gas. International Journal of Nano and Biomaterials, 2009, 2(1-5), p. 409-415. Zitha, PLJ. Smart fluids in the oilfield. Exploration & Production: The Oil & Gas Review, 2005, p. 66-68. Shokrlu, YHaTB. Effects of nano-sized metals on viscosity reduction of heavy oil/bitumen during thermal applications, in Canadian Unconventional Resources and International Petroleum Conference., 2010, Society of Petroleum Engineers: Calgary, Alberta, Canada.

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[10] Ju, B; Tailiang, Fan; Mingxue, Ma. Enhanced oil recovery by flooding with hydrophilic nanoparticles. China Particuology, 2006, 4(1), p. 41-46. [11] Ju, BaTF. Experimental study and mathematical model of nanoparticle transport in porous media. Powder Technology, 2009, 192(2), p. 195-202. [12] Karimi, A; Zahra, Fakhroueian; Alireza, Bahramian; Nahid, P. Khiabani; Jabar, B. Darabad; Reza, Azin; Sharareh, Arya. Wettability alteration in carbonates using zirconium oxide nanofluids: EOR implications. Energy & Fuels, 2012, 26(2), p. 1028–1036. [13] Maghzi, A; Ali, Mohebbi; Riyaz, Kharrat; Mohammad, H. Ghazanfari. Pore-scale monitoring of wettability alteration by silica nanoparticles during polymer flooding to heavy oil in a five-spot glass micromodel. Transport in Porous Media, 2011, 87(3), p. 653– 664. [14] Franco, CA; Tatiana, Montoya; Nashaat, N. Nassar; Pedro, PereiraAlmao; Farid, B. Cortés. Adsorption and Subsequent Oxidation of Colombian Asphaltenes onto Nickel and/or Palladium Oxide Supported on Fumed Silica Nanoparticles. Energy & Fuels, 2013, 27(12), p. 7336-7347. [15] Rouquerol, F; Jean, Rouquerol; Philip, Llewellyn; Kenneth, Sing. Adsorption by powders and porous solids: principles, methodology and application., 2013, Academic Press.

In: Formation Damage in Oil … Editors: C. A. Franco Ariza et al.

ISBN: 978-1-53613-902-0 © 2018 Nova Science Publishers, Inc.

Chapter 8

APPLICATION OF NANOFLUIDS IN FIELD FOR INHIBITION OF ASPHALTENE FORMATION DAMAGE Richard D. Zabala1,*, H. Acuña1, J. E. Patiño2, Farid B. Cortés3,†, Camilo A. Franco 3,‡, S. H. Lopera4, C. Céspedes1, E. Mora1, O. Botero1 and L. Guarín1 1

Gerencia de Desarrollo de Yacimientos, Vicepresidencia Técnica de Desarrollo, Bogotá, Colombia 2 Petroraza S. A., Sabaneta, Colombia 3 Grupo de Investigación en Fenómenos de Superficie–Michael Polanyi, Facultad de Minas, Universidad Nacional de Colombia, Sede–Medellín, Medellín, Colombia 4 Grupo de Investigación en Yacimientos de Hidrocarburos, Facultad de Minas, Universidad Nacional de Colombia Sede–Medellín, Medellín, Colombia *

Corresponding Author Email: [email protected]. Email: [email protected]. ‡ Email: [email protected]. †

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ABSTRACT This chapter describes the use of nanomaterials for asphaltenes inhibition under reservoir conditions. In CP Sur field, some traditional methods have been evaluated for asphaltenes inhibition. Asphaltenes precipitation in the near wellbore has been confirmed as one of the major components of formation damage in CP field. The asphaltenes inhibition test involves the injection of nanofluids containing nanoparticles to adsorb the asphaltenes before being flocculated and transported in the product fluids, thereby avoiding precipitation near the wellbore and downhole. The first part of this chapter describes the adsorption kinetics and the adsorption capacity of various nanomaterials for samples of asphaltenes. The sorption kinetics of asphaltenes on locally produced nano-alumina and other nanomaterials was determined in an asphaltenes concentration range of 250–1500 mg/L. From the results of the laboratory evaluation, it was determined that the locally produced nano-alumina exhibited excellent properties for asphaltenes sorption and may be incorporated into a nanofluid free of aromatic solvents, which are the traditional major components used in the formulations of asphaltenes inhibitors and dispersants. The nanofluid was evaluated in core flow testing under reservoir conditions, and it was observed that the synthesized nanofluid improved the permeability to oil. Then, a pilot test in CP1well was used as a field trial by injecting 220 bbl of nanofluid containing alumina nanoparticles into the geologic formation. After seven months of job tracking, asphaltenes remained stable in produced oil, and the oil production was above the baseline level.

Keywords: nano-alumina, asphaltenes inhibitor, formation damage, nanoparticles

1. INTRODUCTION The CP Sur field [1] is located in the foothills of the eastern mountain chain of the Colombian Andes, close to other fields discovered in this area such as Floreña, Pauto, Volcanera, Receptor, CP, and Cusiana. Despite the fact that CP Sur is very close to CP, but is totally independent and separate.

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CP Sur was formed by a back thrust structure with several reservoir pressures, properties, and contact fluids. CP Sur is a compositional volatile oil reservoir with an average API gravity of 38°; there is no free gas cap at initial conditions. The main formations in CP Sur are MI and BC, which are quite similar in their petrophysical and fluid properties (average permeability is 21 mD, and the average porosity is 6.5%). CP Sur is a prolific oil field that during fifteen years of production has recovered 88 MMstb gross out of 189 MMstb originally in place. The hydrocarbon was produced from MI and BC reservoirs in a developed area with four producer and two injector wells. The current reservoir conditions that are anticipated in the CP Sur field are highly dependent on the way the reservoir has been produced and the gas injection support. The first production well CPXP1 began producing in March 1998, while the first gas injector well was put on injection in January 2000. At that time, one volatile oil well was producing oil. Currently, in this oil field there are six active wells, four producing wells and two gas injectors. Oil production reached its peak in March 2001, which was about 4.2 × 104 SBbl/d. The average gas production (at that date) was 175 MMscfd. Today, the recovery factors are 48.2% for MI and 29.5% for BC. Volatile oil reservoirs are challenging because the largest percentage of the light crude oil contains light saturates, in which asphaltenes have poor solubility. This is the case in CP Sur, where some wells have significant skin damage associated with asphaltenes precipitation. Usually, organic stimulation is performed in the wells of this field with the purpose of periodical organic scale removal. Significant attempts have been made to inhibit asphaltenes by using amino compounds, resins, and other polymers with aromatic naphtha as the solvent. In the CP Sur field, there is a significant history of the use of polymeric asphaltenes inhibitors that have produced positive results. However, these inhibitors have demonstrated a short inhibition life because of the organic nature of the products and the high flow rates that generated low retention of the inhibitor in the reservoir.

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Research concerning organic substances adsorbed onto adsorbent materials has been considered for nearly a century. Asphaltenes inhibition by nanoparticles is a new approach that is based on the earlier concept of adsorption where the adsorbate (Asphaltenes) is adsorbed by the adsorbent (nanoparticles with a huge surface area). Adsorption is a result of surface energy. Inside the adsorbate materials, the bonding requirements of the constituent atoms of the adsorbents are filled by other atoms. However, atoms on the surface of the nanomaterials with huge surface area are not entirely surrounded by other atoms; therefore, they can attract other substances [2]. It was expected that the adsorption of asphaltenes inhibitors on nanoparticles would have a better affinity with the mineral structure of the reservoir rock and would be retained for extended periods. Moreover, it was expected that the injection of nanofluids would effectively extend the life of the organic stimulants. This would prevent asphaltenes precipitation downhole and at perforations while maintaining a sufficient residual concentration of nanoparticles within the reservoir, thus inhibiting new oil from flowing into the well.

2. MATERIALS AND METHODS 2.1. Materials In this study, n-Heptane (99%, Sigma-Aldrich, St. Louis, MO) was used as received for isolation of n-C7 asphaltene and for the preparation of heavy oil model solutions. Toluene (99.5%, Merck KGaA, Germany) was also used for the preparation of heavy oil solutions. Clean silica sand (Ottawa sand, US sieves 30−40 mesh) was purchased from Minercol S. A. Colombia and was used as a porous media. Moreover, toluene, methanol (99.8%, Panreac, Spain), and HCl (37%, Panreac, Spain) were used for porous media cleaning.

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2.1.1. Nanoparticles Alumina nanoparticles were supplied by Petroraza SAS (Colombia). Nanoparticles were characterized by N2 adsorption at 77 K and dynamic light scattering (DLS) to determine their surface area and particle size. Nitrogen adsorption isotherms were obtained using an Autosorb-1 obtained from Quantachrome after outgassing the samples overnight at 413 K under high vacuum (10–6 mbar). BET surface area values were calculated using the Brunauer, Emmet, and Teller model (BET) [3]. DLS measurements were performed using a Vasco Particle Size Analyzer (Cordouan Technologies, France). From these results, alumina nanoparticles were found to have a surface area of 207.7 ± 0.5 m²/g with an average particle diameter between 80 and 110 nm. The nanofluid was prepared using a mixture of solvents as the carrier fluid for the alumina nanoparticles. The physical properties of this carrier fluid or mixture of solvents was formulated to maintain the nanoparticles in suspension and at a sufficiently low surface tension to sustain an appropriate dispersion of the nanoparticles. The solvent mixture was also selected such that it provided good compatibility with the nanomaterial, thereby avoiding any further reactions that would degrade or adversely affect the nanoparticles. Aromatic solvents were not included in the nanofluid for environmental reasons. Finally, the nanofluid was prepared and its effectiveness was evaluated in a core plug obtained from the CP Sur field. 2.1.2. n-C7 asphaltene Initial n-C7 asphaltene samples were isolated following a standardized procedure. This was accomplished by adding an excess of n-heptane to the crude oil in a volume ratio of 40/1. The mixture was sonicated for 2 h at 298 K and further stirred at 300 rpm for 20 h. The precipitated fraction was filtered using a 8-μm Whatman filter paper and washed with n-heptane at a ratio of 4/1 (g/ml). The n-C7 asphaltene samples were centrifuged at 4500 rpm for 15 min and left to rest for 24 h. The cake was washed with nheptane several times until the color of the asphaltenes became shiny black. Then, the sample was dried in a vacuum oven at 298 K for 12 h.

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Finally, the resulting n-C7 asphaltene was homogenized using a mortar and pestle. The precipitated asphaltenes were redissolved in toluene to prepare a stock solution of 3000 mg/l.

2.2. Experimental Methods 2.2.1. Adsorption Experiments Batch-mode adsorption experiments were performed at a ratio of 1:10 (L:g) of a model heavy oil solution: the mass of nanoparticles, following a procedure described in previous work [4, 5]. In brief, the adsorption of asphaltene in these experiments was monitored for 100 min at a fixed asphaltene initial concentration, and the solution temperature was maintained at 298 K. Three different asphaltenes dilutions were prepared with initial concentrations of 250, 750, and 1500 mg/L from a stock solution. Aliquots of the test solution were removed at predetermined time intervals and analyzed for their asphaltene concentration by using a Genesys 10S UV-vis spectrophotometer (Thermo Scientific, Waltham, MA). The adsorbed amount of n-C7 asphaltenes relative to the mass of nanoparticles (mg/g) was estimated following the mass balance, where (mg/g) and (mg/L) were the concentrations of asphaltenes in the solution at a given time (min) and (g/L) was the ratio of the dry mass of nanoparticles to the solution volume. 2.2.2. Core-flooding Tests These tests were fundamental for evaluating the effectiveness of the nanoparticles for asphaltene inhibition in a porous media and for determining the effect of permeability in a porous media after each flooding test stage. Figure 1 shows a schematic representation of the experimental apparatus. The setup mainly comprised a tank containing the nanofluid, a commercial pump (Cole-Parmer Instrument Co., Canada), a positive displacement pump (DB Robinson Group, Canada), fraction collectors, and a stainless steel column reactor. The nanofluid mixtures were injected into the porous media from the injection point using the

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positive displacement pump. In this case, the oil and water were pumped through a filter to retain any solids that were suspended in the fluid. The nanofluid was not pumped through the filter. All tests were conducted at a typical reservoir temperature and pore pressure (maintained at this value with a pressure multiplier). To maintain the reservoir conditions, the overburden pressure was kept at the desired value by pumping an incompressible fluid to the core holder using a different pump, which is indicated as number 5 in Figure 1. To maintain the test temperature, the outside body of the reactor column was covered with heating tapes, and the column was insulated with a fiber glass casing. A leak test was performed by pressurizing the packed bed reactor with pure nitrogen up to 6.9 MPa. A 1% change in pressure per hour was considered to be the maximum allowable pressure reduction during the leak test. For the displacement tests using the porous media, the chemical nature of the nanoparticles and their concentration in the aqueous solution were selected from the batch adsorption experiments results. The main objective of this displacement test was to evaluate the effectiveness of the nanoparticles for inhibiting the asphaltenes precipitation (e.g., formation of i-mers) and the effectiveness of the complex multi-mechanism process (e.g., flocculation, precipitation, and layering) that causes rapid growth of deposits and subsequently reduces porosity and permeability of the flow channels and the deposition of asphaltenes. The displacement test was performed by (1) constructing the base curves and (2) identifying the influence of the nanoparticles when asphaltenes damage (precipitation and deposition) was induced. For the construction of the base curves, 10 pore volumes (PV) of water were injected to measure the absolute permeability. Then, at the same temperature and under the saturation conditions of residual water (Swr), the crude oil was injected until the pressure stabilized. Finally, 20 PV of water were injected to build the relative permeability curves as a function of the water saturation. For the evaluation of the effectiveness of nanoparticles after asphaltenes damage was induced, the packed bed was saturated with the injection of 2 PV of crude oil and the displaced volume of water in the porous media was measured. To study the inhibition or delay of asphaltenes precipitation, 0.5 PV of nanofluids were injected

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simultaneously with crude oil, followed by the injection of 0.5 PV of nheptane into the reactor. Immediately, the permeability to the crude oil was measured. Then, 20 PV of water were injected to measure the relative permeability and the Np curve. For induced asphaltenes damage, 50 PV of crude oil were injected to remove any chemical content in the porous media, and the displaced water was measured. Then, 0.5 PV of n-heptane were injected to generate damage and measure the effective permeability to oil.

Figure 1. Diagram of the displacement test: (1) core holder, (2) core (Ottawa Sand Packing), (3) pore pressure diaphragm, (4) pump one, the positive displacement pump, (5) pump two, (6) displacement cylinder, (7) filter, (8) pressure multiplier, (9) manometer, (10) valve, and (11) test tube.

2.3. Field Trial conditions 2.3.1. Well Candidate Selection The CP1 well was the pilot well selected for the field trial of the new stimulation technology with nanoparticles. This well was considered to be a good candidate for two reasons:

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1. Precipitation of asphaltenes occurs in the CP1 reservoir, and traditional methods for inhibiting asphaltenes at the reservoir level were not effective. In addition, asphaltenes inhibitors and asphaltenes dispersants have a similar chemical composition. These are mixtures of organic acids and derivatives of aromatic hydrocarbons, which can disperse diluted deposits in the crude oil when injected into the reservoir. However, there is a low possibility of maintaining a residual in the reservoir. 2. Past interventions in the well CP1 have shown significant benefits from this job. Information related to the formation damage mechanism can be obtained by using clear interpretations, analysis of production data, and laboratory testing of the well fluid. The CP1 well was completed at the MI and BC formations. The main wellbore damages are as below: organic deposits (asphaltenes), presence of inorganic deposits, (possibly barium sulfate (BaSO4) in BC formation and calcium carbonate (CaCO3) in MI formation), blocking fluid problems (condensate water, completion fluid, etc.), and fines migration as shown in the skin characterization diagram in Figure 2.

Figure 2. Skin characterization diagram for CP1 well including mineral scale parameter (MSP), fines blockage parameter (FBP), organic scale parameter (OSP), relative permeability parameter (KrP), induced damage parameter (IDP), and geomechanical damage parameter (GDP).

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2.3.2. Stimulation and Inhibition Job Strategy in CP1 Sur Well The stimulation of the proposed job was performed in several stages. These included a pickling job to dissolve carbonate scales, an organic treatment stage to dissolve organic scales, and an inhibition job in CP1 in the last stage that was conducted in December 2012 by pumping 220 bbls of nanofluid containing alumina nanoparticles and 411 bbls of displacing fluid to reach the desired penetration radius of 7.2 ft. For a displacing fluid (over flush), a mixture of diesel, alcohol, and xylene was used. A coiled tubing unit was used, and a selective packer was set between the MI and BC formations, the job was performed by pumping fluid at a very low rate and pressures below the fracture gradient. After 12 h of soaking time, the wells were opened for production at controlled flow rates.

3. RESULTS AND DISCUSSIONS 3.1. Adsorption Kinetics Figure 3 shows the evolution over time of the amount of adsorbed asphaltenes calculated from the concentration measurements for an initial asphaltene concentration of 250, 750, and 1500 mg/L at a setup

Figure 3. Amount of asphaltene adsorbed on alumina nanoparticles versus time for the different initial concentration of asphaltenes.

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temperature of 298 K. As shown in Figure 3, the adsorption was highly dependent on the initial concentration of the asphaltenes. The equilibrium condition was achieved faster for a lower initial asphaltene concentration: 2 min at 250 mg/L and 750 mg/L and 80 min at 1500 mg/L. This fast asphaltene adsorption may have been caused by the intermolecular forces between the most polar asphaltene components (mostly functional groups and heteroatoms) and the functional groups on the alumina surface.

3.2. Core-Flooding Test with Nanofluid Figure 4 shows the acquired relative permeability curves. The aim of this investigation was to determine if the nanoparticles were capable of preventing agglomeration and inhibition of formation damage, which is caused by the precipitation and subsequent deposition of asphaltenes. As observed in Figure 4, positive changes in the relative permeability after the injection of 0.5 PV of the nanofluid containing nanoparticles was obtained. In the core-flooding tests, the relative permeability to oil visibly increased after application of the fluid containing alumina nanoparticles. Changes in oil effective permeability showed an alteration of the permeability by asphaltenes precipitation. After n-heptane injection without inhibition, asphaltenes precipitation created a skin damage that was more than 99% compared to the original permeability. After application of the nanofluid containing nanoparticles for asphaltenes inhibition, an additional 34% reduction in skin damage was achieved. Inhibition was observed after application of nanoparticles, and the oil effective permeability was maintained for a long time after 50 PV of oil was injected, illustrating the perdurability of the treatment. Table 1 summarizes the effective permeability to oil and the effective permeability to water in a porous media after each flooding test stage. These results show that the nanoparticles can significantly inhibit the damage associated with asphaltenes deposition. In Figure 4, it can also be seen that the saturation states changed positively after the nanoparticle injection. This phenomenon most likely occurred either because of nanoparticle deposition onto the

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surface rock, which created a monolayer, or because of the stabilizing effect of the nanoparticles in the porous media, which stabilized the asphaltenes in the crude oil by the interaction of intermolecular forces. The latter phenomenon could control the water production in hydrocarbon reservoirs in a manner similar to conventional relative permeability reducers (RPM). Moreover, based on Figure 4, it appeared that the oil relative permeability curve was displaced to the right by the nanofluid treatment. This implied that the oil effective permeability at a given water saturation increased as the wettability changed from an oil-wet to a waterwet condition. According to Craig’s rule of thumb [6], this value is typical for strongly water-wet cores. A high saturation of the wetting phase is required at the crossover point to compensate for its lower mobility.

Figure 4. Relative permeability curves before and after nanoparticles injection.

Table 1. Effective permeability to Oil and Effective permeability to water in a porous media after each flooding test stage Stage

After Asphaltenes precipitation with n-heptane (Induced skin without inhibition) After treatment with nanoparticles After second Asphaltenes precipitation with n-heptane (Induced Skin after inhibition)

Effective permeability to Oil (mD) 0.09

Effective permeability to water (mD) 13.89

10.78 2.54

15.72 6.48

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3.3. Field Application Figure 5 shows the net production in well CP1 after the tasks were performed in this well on December 2012. The production performance after inhibition stimulation was monitored for nearly 8 months, where the last three months of production exhibited a constant output of 300 BLS above the baseline. Before and after the job and even in between the stages of the well intervention, production well tests were run to evaluate well performance as shown in the graphics a–d from Figure 6. The key findings are as follows:  



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The net initial incremental oil rate was 1280 Bopd. The API performance increased from 40 at the beginning of the stimulation job to 41.5 at the end of the inhibition with nanoparticles stage. Nodal system analysis showed an improvement in IPR (Skin reduction), and the VLP performance was altered due to the increase in oil production. The production performance after inhibition stimulation has been monitored for almost 8 months, from which the last three months of production showed a steady behavior of 300 BLS above the baseline.

As part of the nanofluid performance tracking, free nanoparticles of nano-alumina were measured in produced water, as an indicator of the available amount of inhibitor in the formation. These data were compared to the asphaltenes content in produced oil, before and after the job. Figure 7a, b shows residual free nanoparticles in the water against a) asphaltenes concentration and b) oil production. Note that it can be seen in Figure 7a that at the beginning of the treatment, the asphaltenes concentration in the oil was less than 3% for the first 40 days. Afterwards, the asphaltenes concentration increased to 4%. Moreover, in Figure 7, it can be seen that 215 days after the application in well CP1, more than 150,000 barrels of

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additional cumulative production was achieved in well CP1 and inhibitor residual values were about 0.1 mg/l in the produced water. This value may be considered as the minimum acceptable concentration of nanoparticles that guarantees effective asphaltenes inhibition in this well.

Figure 5. Incremental Production after CP1 Job.

a) Figure 6. (Continued).

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c)

d) Figure 6. Well Performance after each stage CP1 for a) Gas performance, b) oil performance, c) API variation, and d) nodal system analyses.

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a)

b) Figure 7. Residual nanoparticles against a) asphaltenes concentration and b) oil production.

CONCLUSION 

Incremental production of 1200 bbls after organic and inorganic remotion stages indicated that the formation damage mechanisms were the primary factors that affected the productivity of CP1 as according to characterization and laboratory tests.

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Post nanoparticle inhibition increased production by 80 BOPD. This increase was not expected, because the inhibition was intended to extend the life of the stimulation process. The concentration of nanoparticles in output water showed that up to a specific date, the inhibition process remained active, which was indicated by the above baseline production performance. It appeared that 0,1 PPM of free nanoparticles in produced water is very near to the minimum concentration of inhibitor, for this type of nanofluid. The experimental study allowed the evaluation of the effectiveness of nanofluids containing alumina nanoparticles with high surface area for asphaltenes inhibition. Well stabilized nanofluids containing alumina nanoparticles showed good performance in the reservoir, even under very low permeability conditions. Nanofluids containing alumina nanoparticles showed good retention in the formation for more than 8 months. Monitoring of nanoparticle concentrations in the product water may be a key indicator of remaining inhibitor into the formation.

REFERENCES [1]

[2]

Franco Carlos A, R. D. Z., Jose Zapata, Edgar Mora, Oscar Botero, Carlos Candela and Andres Castillo, Inhibited Gas Stimulation To Mitigate Condensate Banking and Maximize Recovery in CP Field. Society of Petroleum Engineers, 2013. 28(2): p. 154-167. Ferrari, L., Josef Kaufmann, Frank Winnefeld and Johann Plank, Interaction of cement model systems with superplasticizers investigated by atomic force microscopy, zeta potential, and adsorption measurements. Journal of Colloid and Interface Science, 2010. 347(1): p. 15-24.

324 [3]

[4]

[5]

[6]

Richard D. Zabala, H. Acuña, J. E. Patiño et al. Rouquerol, F., Jean Rouquerol and Kenneth Sing, Adsorption by powders and porous solids: principles, methodology and applications. 2013: Academic Press. Franco, C. A., Tatiana Montoya, Nashaat N. Nassar, Pedro PereiraAlmao and Farid B. Cortés, Adsorption and Subsequent Oxidation of Colombian Asphaltenes onto Nickel and/or Palladium Oxide Supported on Fumed Silica Nanoparticles. Energy & Fuels, 2013. 27(12): p. 7336-7347. Nassar, N. N., Stefania Betancur, Sócrates Acevedo, Camilo A. Franco and Farid B. Cortés, Development of a Population Balance Model to Describe the Influence of Shear and Nanoparticles on the Aggregation and Fragmentation of Asphaltene Aggregates. Industrial & Engineering Chemistry Research, 2015. 54(33): p. 8201-8211. Anderson, W. G., Wettability literature survey part 5: The effects of wettability on relative permeability. Journal of Petroleum Technology, 1987. 39(11): p. 1453-1468.

ABOUT THE EDITORS Dr. Camilo Andrés Franco Ariza, PhD Assistant Professor Researcher at the “Michael Polanyi” Research Group in Surface Phenomena, Facultad de Minas, Universidad Nacional de Colombia – Sede Medellín Medellín, Colombia Email: [email protected]

Dr. Farid Bernardo Cortés Correa, PhD Full Professor Director of the “Michael Polanyi” Research Group in Surface Phenomena, Facultad de Minas, Universidad Nacional de Colombia – Sede Medellín Medellín, Colombia

INDEX A absolute permeability, 168, 173, 259, 267, 292, 293, 313 adsorption, xi, xiii, 35, 60, 84, 91, 111, 122, 127, 137, 157, 160, 161, 162, 178, 179, 186, 187, 188, 189, 190, 191, 192, 193, 195, 196, 198, 199, 200, 202, 203, 204, 205, 206, 207, 211, 219, 221, 224, 226, 227, 233, 252, 262, 270, 280, 288, 290, 291, 292, 294, 295, 296, 297, 305, 306, 308, 310, 311, 312, 313, 316, 317, 323, 324 adsorption isotherms, xi, 179, 186, 198, 202, 204, 205, 207, 221, 291, 292, 295, 296, 311 adsorption kinetics, xiii, 308, 316 aggregates, 31, 32, 34, 37, 44, 116, 157, 179, 190, 193, 205, 228, 229, 296, 324 arc-discharge method, 98 asphaltene, vii, ix, xii, 3, 10, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 62, 64, 65, 66, 67, 68, 155, 157, 163, 164, 177, 178, 179, 227, 228, 286, 288, 291, 295, 297, 305, 307, 310, 311, 312, 316, 317, 324

asphaltenes inhibition, xiii, 289, 305, 308, 317, 320, 323 asphaltenes inhibitor, xiii, 308, 309, 310, 315 association, 28, 32, 34, 67, 199, 205

B bimetallics, 113 bottom-up, ix, 71, 72, 73, 76, 100, 101, 117, 119, 124, 128, 129, 139, 141 breakthrough curve, 263, 264

C carbon nanofibers, 83, 102, 125, 142 carbon nanospheres (CNSs), 105, 106, 107, 109, 110, 111, 113, 143, 144, 145, 147 carbon nanotubes (CNTs), 83, 84, 92, 94, 95, 96, 98, 99, 100, 101, 106, 125, 139, 140, 141, 144, 279 carbon-based nanomaterials, ix, 72, 82 ceramic materials, 114, 115, 116, 163 ceramics, 74, 113, 114, 116, 149 chemical exfoliation, 85, 125

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chemical synthesis, 92 chemical vapor deposition, 90, 99, 106, 125, 138, 148 contact angle, x, 150, 154, 155, 158, 161, 165, 172, 173, 175, 257, 288 co-precipitation, 78 core-flooding tests, 317 critical rate, xii, 55, 57, 58, 59, 61, 68, 232, 253, 256, 258, 259, 260, 266, 268, 270, 284

D degradation, x, 77, 186, 188, 191, 200, 216, 217, 218, 219, 220, 221, 222, 224, 225 degradative effects, 185, 188, 198 deposition, vii, ix, 8, 9, 27, 28, 32, 37, 38, 40, 44, 45, 51, 52, 56, 59, 60, 61, 62, 64, 67, 68, 91, 100, 102, 105, 118, 125, 142, 144, 148, 149, 163, 164, 168, 235, 240, 242, 243, 244, 245, 246, 272, 274, 276, 277, 288, 313, 317 desorption, 137, 195, 196, 200, 202, 203, 221 diagnostics, 29, 61 disaggregation, 2 displacement test, x, xii, 57, 63, 154, 163, 167, 173, 176, 178, 188, 232, 253, 255, 258, 288, 290, 292, 293, 297, 305, 313, 314 displacement tests, 167, 188, 255, 290, 292, 293, 297, 313

E electrochemical exfoliation, 88, 125, 134, 135 enhanced oil recovery, x, 73, 180, 181, 183, 185, 186, 187, 223, 224, 225, 226, 227, 250

enhanced oil recovery (EOR), x, 73, 181, 183, 186, 187, 189, 191, 193, 194, 205, 212, 222, 223, 225, 226, 250, 279, 286, 287, 306 epitaxial growth, 89, 125 extra-heavy oil, 163, 254, 285

F fabrication methods, viii, 71 field, viii, xi, xii, xiii, xiv, 8, 9, 29, 55, 58, 73, 81, 82, 83, 87, 92, 96, 102, 121, 132, 140, 164, 177, 178, 189, 227, 228, 231, 232, 234, 239, 246, 248, 251, 253, 255, 259, 268, 270, 277, 279, 282, 285, 286, 289, 292, 298, 299, 300, 303, 304, 307, 308, 309, 311, 314, 319, 323 field application, 298, 319 field test, xi, 232, 234, 285 field trial, xiii, xiv, 231, 234, 254, 268, 270, 286, 308, 314 fines, vii, ix, xi, 3, 4, 12, 15, 16, 25, 27, 28, 29, 51, 52, 53, 54, 55, 56, 57, 58, 59, 62, 63, 68, 155, 178, 231, 232, 233, 234, 235, 236, 237, 244, 245, 247, 248, 249, 251, 253, 255, 256, 257, 258, 261, 262, 263, 264, 265, 266, 270, 271, 272, 273, 274, 276,277, 278, 279, 282, 283, 284, 315 fines deposits, 29, 51 fines migration, vii, xi, 15, 29, 55, 68, 155, 231, 232, 233, 234, 235, 249, 251, 253, 258, 262, 263, 264, 266, 270, 271, 272, 273, 276, 277, 278, 279, 282, 283, 284, 315 fines retention test, 253, 255, 256, 258, 261, 270 formation damage, vii, viii, ix, x, xiii, 1, 2, 3, 25, 26, 27, 28, 29, 51, 55, 61, 62, 69, 73, 155, 163, 164, 170, 176, 178, 185, 186, 188, 189, 191, 193, 222, 223, 224,

Index 231, 233, 234, 235, 236, 246, 249, 250, 251, 271, 272, 274, 275, 276, 277, 278, 279, 283, 299,303, 307, 308, 315, 317, 322

G graphene, 83, 84, 85, 87, 88, 89, 90, 91, 92, 94, 95, 99, 101, 105, 106, 125, 132, 133, 134, 135, 136, 137, 138, 139, 228

H heavy oil, xii, 66, 127, 163, 178, 179, 181, 187, 223, 225, 274, 281, 285, 286, 287, 289, 305, 306, 310, 312 Herschel-Bulkley model, xi, 186, 199 hydrolyzed polyacrylamide (HPAM), xi, 186, 190, 193, 197, 201, 202, 205, 209, 212, 217, 219, 221, 224, 226, 229 hydrothermal treatment, 105, 107, 125

I inhibition, vii, viii, xii, xiii, 155, 178, 188, 210, 231, 232, 234, 250, 253, 262, 263, 264, 265, 266, 270, 288, 304, 307, 308, 309, 310, 312, 316, 317, 318, 319, 323 inhibition of asphaltene, 304 IOR, 286, 287 isotherms, xi, 186, 195, 202, 203, 204, 205, 206, 207, 221, 288, 295, 296, 305

L laboratory, viii, ix, xi, xiii, 2, 10, 28, 34, 39, 55, 58, 60, 61, 62, 63, 68, 75, 115, 192, 231, 232, 251, 253, 254, 271, 273, 284, 303, 308, 315, 322 laser ablation, 97, 98, 100

329

level of risk, viii low-permeability reservoirs, 231

M mathematical model, 40, 47, 59, 60, 62, 243, 244, 247, 273, 306 mechanical exfoliation, 84, 85, 125 metallic nanomaterials, 113 methodology, viii, ix, 1, 2, 3, 4, 9, 22, 25, 27, 28, 29, 62, 73, 77, 79, 97, 196, 204, 207, 306, 324 microwave-assisted nanoparticle synthesis, 80 mobility, x, xii, 132, 154, 183, 187, 188, 189, 224, 229, 266, 285, 286, 287, 289, 293, 300, 301, 303, 318 multiparameter methodology, 1, 2, 4, 25 multi-walled CNTs (MWCNTs), 93, 95

N nano-alumina, xiii, 308, 319 nanodiamonds, 83, 103, 104, 125, 142 nanofluid(s), viii, x, xi, xii, xiii, xiv, 73, 126, 153, 154, 155, 161, 162, 165, 166, 167, 168, 171, 172, 173, 175, 176, 177, 181, 182, 183, 186, 188, 191, 192, 205, 225, 226, 229, 232, 233, 234, 247, 249, 251, 253, 261, 262, 270, 272, 273, 278, 284, 285, 286, 287, 288, 289, 290, 292, 294, 297, 299, 300, 302, 303, 304, 305, 306, 307, 308, 310, 311, 312, 316, 317, 319, 323 nanomaterial(s), ix, xii, xiii, 72, 73, 74, 77, 82, 83, 117, 121, 124, 125, 148, 150, 151, 183, 251, 279, 286, 287, 289, 308, 310, 311 nanoparticle, viii, xii, 71, 72, 73, 117, 122, 124, 126, 127, 131, 154, 161, 162, 170, 172, 173, 176, 177, 185, 188, 192, 194,

330

Index

195, 196, 198, 199, 203, 205, 208, 209, 215, 219, 222, 225, 226, 227, 233, 252, 257, 262, 279, 283, 285, 286, 287, 289, 291, 294, 306, 317, 323 nanoparticle synthesis, 72, 117 non-thermal processes, 187

O oil-wet, x, xii, 154, 156, 157, 158, 159, 160, 161, 162, 165, 173, 174, 181, 232, 253, 255, 256, 262, 263, 264, 265, 266, 270, 288, 293, 303, 318

P paraffin, 28, 29, 32, 42, 43, 44, 45, 46, 47, 50, 51, 62, 68, 157 paraffin deposits, 28, 42 particle deposition, ix, 28, 62, 276 permeability, ix, x, xi, xiv, 3, 4, 19, 21, 27, 28, 45, 52, 53, 55, 56, 57, 58, 59, 60, 62, 63, 68, 154, 160, 168, 173, 174, 176, 188, 189, 210, 232, 233, 234, 235, 236, 244, 246, 247, 248, 251, 253, 258, 259, 266, 269, 271, 274, 276, 277, 278, 285, 287, 289, 292, 293, 308, 309, 312, 315, 317, 318, 323, 324 pilot test, xiv, 253, 269, 270, 308 polymer, x, 17, 18, 19, 40, 65, 66, 96, 102, 103, 106, 122, 146, 177, 185, 186, 187, 188, 189, 190, 191, 192, 193, 194, 195, 196, 197, 198, 199, 200, 201, 202, 203, 204, 205, 206, 207, 208, 209, 210, 211, 212, 213, 214, 215, 216, 217, 218, 219, 220, 221, 222, 223, 224, 225, 226, 227, 228, 229, 248, 249, 278, 306 polymer flooding, 189, 190, 191, 193, 210, 212, 221, 226, 227, 306 polymer injection, x, 186, 187

pore, x, 32, 53, 54, 55, 59, 105, 116, 168, 181, 186, 188, 190, 191, 208, 210, 222, 228, 235, 236, 240, 242, 244, 245, 255, 256, 257, 258, 260, 261, 262, 264, 274, 275, 277, 286, 287, 292, 293, 306, 313, 314 pore throat, x, 54, 186, 188, 191, 208, 210, 222, 237, 240, 242, 255, 258, 262 porous medium, 29, 52, 54, 56, 57, 59, 63, 156, 159, 167, 168, 171, 189, 190, 191, 192, 193, 207, 210, 211, 221, 225, 234, 236, 237, 239, 240, 241, 245, 246, 251, 256, 257, 260, 266 precipitation, vii, ix, xiii, 10, 26, 27, 28, 29, 31, 32, 34, 35, 36, 37, 38, 39, 40, 41, 43, 44, 45, 46, 47, 49, 50, 54, 63, 64, 65, 66, 67, 78, 79, 80, 99, 122, 125, 155, 156, 157, 163, 164, 168, 177, 179, 288, 298, 308, 309, 310, 313, 315, 317, 318 precipitation of asphaltene, 34, 37, 38, 40, 298 pseudoplastic, 199, 212, 214, 216, 217 pyrolysis of hydrocarbons, 125, 144

R reactive grinding/ball milling, 74 relative permeability curves, 158, 168, 173, 293, 298, 303, 313, 317 retention, x, 59, 185, 186, 187, 189, 190, 191, 193, 196, 197, 200, 207, 210, 211, 221, 224, 235, 240, 242, 243, 244, 246, 250, 252, 253, 255, 256, 258, 259, 261, 264, 265, 266, 270, 276, 278, 309, 323 retention test, 196, 197, 200, 210, 253, 256, 259 rheological behavior, xi, 186, 192, 193, 198, 199, 200, 212, 215, 217, 219, 225, 226

Index

331

S

T

sandstone, xii, 153, 155, 161, 177, 182, 224, 231, 232, 244, 271, 273, 275, 284, 288, 305 saturates, aromatics, resins, and asphaltenes (SARA), 7, 8, 9, 10, 26, 29, 38, 39, 40 shear-thinning, 212 silica, x, xi, 105, 112, 113, 114, 115, 120, 126, 146, 147, 148, 149, 153, 154, 163, 178, 181, 183, 192, 193, 194, 196, 225, 226, 227, 231, 232, 233, 234, 251, 253, 254, 270, 278, 284, 305, 306, 310, 324 silica-based nanofluids, 231 single-walled nanotubes, 95 single-walled nanotubes (SWNTs), 95, 98, 99, 100 size aggregate, 187 skin, viii, 1, 2, 3, 4, 22, 23, 24, 25, 26, 277, 299, 300, 301, 302, 303, 304, 309, 315, 317, 318, 319 skin characterization diagram, 23, 315 skin factor, 2, 25, 277 sol–gel polymerization, 110, 111, 125 solid-liquid equilibrium (SLE) model, xi, 186, 198, 199, 202, 204, 205, 206, 221 solubility parameter, 31, 35, 36, 40, 41, 50 solvothermal, 76, 77, 78, 120, 124, 125, 129, 130, 228 spontaneous imbibition, 155, 160, 161, 165, 169, 170, 172 surfactant, x, 113, 130, 133, 154, 155, 157, 160, 161, 162, 163, 166, 167, 169, 170, 171, 172, 176, 177, 178, 180, 181, 225, 282, 288

thermodynamic models, 35, 45 top-down, ix, 71, 72, 73, 74, 117, 118, 119, 124, 128, 149

U ultrasound-assisted nanoparticle synthesis, 79 unzipping carbon nanotubes, 92

V viscosity, xii, 28, 37, 44, 45, 56, 71, 73, 124, 127, 163, 164, 187, 188, 189, 191, 192, 193, 199, 209, 212, 214, 215, 217, 237, 254, 255, 285, 286, 287, 289, 290, 291, 297, 298, 300, 301, 302, 303, 304, 305

W water-wet, x, xii, 154, 156, 158, 159, 161, 162, 165, 170, 172, 173, 174, 192, 232, 253, 261, 262, 263, 264, 265, 266, 288, 293, 302, 303, 318 well candidate selection, 314 wettability, ix, x, xii, 27, 28, 53, 54, 153, 154, 155, 156, 157, 158, 159, 160, 161, 162, 163, 164, 165, 166, 167, 168, 170, 172, 173, 175, 176, 177, 179, 180, 181, 182, 188, 192, 226, 244, 257, 264, 266, 284, 286, 287, 288, 293, 298, 303, 305, 306, 318, 324 wettability alteration, xii, 153, 156, 159, 160, 161, 162, 170, 176, 177, 181, 226, 286, 287, 306