UNIVERSITY OF CALGARY. Nanoparticle-based Drilling Fluids with Improved Characteristics. Mohammad Ferdous Zakaria A THESIS

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1 UNIVERSITY OF CALGARY Nanoparticle-based Drilling Fluids with Improved Characteristics by Mohammad Ferdous Zakaria A THESIS SUBMITTED TO THE FACULTY OF GRADUATE STUDIES IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE DEGREE OF DOCTOR OF PHILOSOPHY DEPARTMENT OF CHEMICAL AND PETROLEUM ENGINEERING CALGARY, ALBERTA SEPTEMBER, 2013 Mohammad Ferdous Zakaria 2013

2 Abstract The success of well-drilling operations is heavily dependent on the drilling fluid. Drilling fluids cool down and lubricate the drill bit, remove cuttings, prevent formation damage, suspend cuttings and also cake off the permeable formation, thus retarding the passage of fluid into the formation. During the drilling through induced and natural fractures, huge drilling fluid losses lead to the higher operational expenses. That is why, it is vital to design the drilling fluid, so that it may minimize the mud invasion in to formation and prevent lost circulation. Typical micro or macro sized lost circulation materials (LCM) show limited success, especially in formations dominated by micro and nano pores, due to their relatively large sizes. The objective of this thesis was to investigate the performance improvement by the usage of NPs (nanoparticles) as lost circulation additives in the drilling fluid. In the current work, a new class of nanoparticles (NPs) based lost circulation materials has been developed. Two different approaches of NPs formation, and addition, to water based and invert-emulsion drilling fluid have been tested. All NPs were prepared in-house either within the invert-emulsion drilling fluid; insitu, or within an aqueous phase; ex-situ, which was eventually blended with the drilling fluid. The laboratory measurements included measuring mud weight, ph, lubricity viscosity, gel strength, standard API LTLP filter test and high temperature and high pressure (HTHP) test. In this work we evaluated fluid loss performance of a wide range of NPs preferably selected from metal hydroxides, e.g. iron hydroxide, metal carbonates, e.g. calcium carbonate and metal sulfate and sulfide e.g barium sulphate and ferrous sulfide respectively. The use of improved NP-based invert emulsion drilling fluid showed an excellent fluid loss control, rheological properties together with a good lubricity profile. This thesis reports an experimental and theoretical study on filtration properties of invert emulsion drilling fluids under static conditions. Under API standard filtration test at LTLP and HTHP, more than 70% reduction in fluid loss was achieved in the presence of 1-5 wt% NPs. ii

3 The results have also shown that the filter cake developed during the NP-based drilling fluid filtration was thin (thickness less than 1 mm), which implies high potential for reducing the differential pressure sticking problem, formation damage and torque and drag problems while drilling. Moreover, at the level of NPs added, no impact on drilling fluid apparent viscosity, and the fluid maintained its stability for more than 4 weeks. Other NPs prepared by in-situ and ex-situ method also showed an excellent fluid loss control. Results of the modeling showed that NP-based drilling fluid didn t follow the Darcy equation at the initiation of filtration and therefore the initial region was found flat and nanoparticles reduced the premeability instantly. It was also shown that nanoparticles transport in filtration was predominantly influenced by the Brownian diffusion. Compare with the drilling fluid alone and drilling fluid with LCM, increasing shear rate did not increase the same extent of shear stress in case of NP-base fluid (both ex-situ and in-situ prepared), which can be attributed to the fact that smaller particles were dispersed more effectively than the larger bulk particles and provided bridging between clay particles due to their larger surface area. Tailor made NPs with specific characteristics is thus expected to play a promising role in solving the circulation loss and other technical challenges faced with commercial drilling fluid during oil and gas drilling operation. iii

4 Acknowledgements All kinds of praise and all thanks belong to ALLAH, the One, the Lord of the Universe, the Creator, the Most Gracious and the Most Merciful. I would like to express my deepest sense of appreciation, gratitude and indebtedness to my respected supervisor Dr. Maen Husein and co-supervisor Dr. Geir Hareland for the opportunity of being part of their research team. Thanks Prof. Husein and Prof.Hareland, it has been a great honor for me to be associated with your team. I greatly appreciate your continuous support, excellent supervision and encouragement throughout this work. I would also like to thank my defense committee members Dr. Roberto Aguilera, Dr. Brij Maini, Dr. Ronald J. Spencer and Dr. T. Nguyen for their time and providing their constructive criticism of my work. It is also a pleasure for me to express again my sincere appreciation and profound regards to Dr. Maen Husein and Dr. Geir Hareland for providing the guidelines to efficiently conduct all the laboratory experiments, constructive suggestions and criticism throughout the period of research work. I am also thankful to Dr. Husein in the final preparation of the manuscript. I am grateful to Ms.Patricia Teichrob for editing my thesis and all kinds of support during my research works. I would also like to extend my sincere thanks to the current and past members of the Nanotechnology for Energy & Environment (NTEE) research team; Salman Alkhaldi, Belal Abu Tarboush, Ahmad Al-As'ad, Alex Borisov, Nashaat Nassar, Zied Ouled Ameur, Amr Abdelrazek Elgeuoshy Meghawry Abdrabo and everyone in the Real-Time Drilling Engineering Research Group for their support, brilliant ideas and encouragement. I wish to thank all the staff of the Chemical Engineering department for their valuable support. Special acknowledgement to Bernie Then and Ms.Paige Deitsch for providing a convenient entourage to conduct the laboratory experiments. I would like to thank team members of nfluids Inc; David Edmonds and Jeremy Krol for their constructive criticism and support in our current research. And I also would like to extend my appreciation to my colleagues at Ineos Oligomers and my family friend iv

5 Dr.Soumaine Dehkissia for their unconditional support in various ways which have inspired me this far. This research was financially supported by a grant from the Natural Science and Engineering Research Council of Canada (NSERC), Talisman Energy Inc and Pason Systems. This support is gratefully acknowledged. Finally, my acknowledgments go to Queen Elizabeth II Graduate (Doctoral) Scholarships for financial support. And last but not the least, I profoundly acknowledge gratefulness to my beloved parents and wife who have provided constant encouragement. v

6 Dedication This works is dedicated to: My lovely supportive parents, brothers and sisters My beloved wife, Asma Sharmin And my wonderful daughter Subah Maknun With love and appreciation vi

7 Table of Contents Abstract... ii Acknowledgements... iv Dedication... vi Table of Contents... vii List of Tables... x List of Figures... xii List of Symbols, Abbreviations and Nomenclature... xv CHAPTER ONE: INTRODUCTION Problem statement and significance of the research Research Objectives Organization of the Thesis...7 CHAPTER TWO: LITERATURE REVIEW Introduction Drilling fluid Classification Functions of Drilling Fluids Drilling fluid related challenges Clay Chemistry used in drilling fluids Nanoparticles Nanoparticle synthesis Nanoparticle-based drilling fluids General characteristics of drilling fluid filtration Filtration mechanism...42 CHAPTER THREE: EXPERIMENTAL METHODS Drilling Fluid Samples NPs and NP-based drilling fluid formation Ex-situ preparation of NPs Fe(OH) 3 NPs CaCO 3 NPs FeS NPs BaSO 4 NPs In-situ preparation Fe(OH) 3 NPs CaCO 3 NPs FeS NPs BaSO 4 NPs Characterization methods and techniques Particle characterization Toxicity evaluation Emulsified water droplet measurement Drilling fluid characterization...58 vii

8 CHAPTER FOUR: RESULTS AND DISCUSSION Fe(OH) 3 Nanoparticles (NPs) Characterization X-ray diffraction analysis Water droplet size distribution Size distribution of ex-situ prepared Fe(OH) 3 NPs Determination of particle size of in-situ prepared Fe(OH) 3 NPs Drilling fluid Characterization Stability of NP-based Fluid LTLP Filtration Commercial NPs In-house prepared Fe(OH) 3 NPs Filtrate Characterization HTHP Filtration Effect of high shear on fluid loss control Effect of presence of organophillic clays on fluid loss Effect of Oil: Water ratio on fluid loss Rheology behavior of NP-based fluid Drilling fluid density and ph Drilling fluid lubricity Preparation and performance evaluation of Fe(OH) 3 NPs in invert emulsion drilling fluids provided by different suppliers Performance of Fe(OH) 3 NPs in water based mud (WBM) Toxicity evaluation Fe(OH) 3 samples CaCO 3 Nanoparticles (NPs) Characterization X-ray diffraction analysis Size distribution of ex-situ prepared CaCO Determination of particle size of in-situ prepared CaCO LTLP Filtration of in-house prepared CaCO 3 NPs HTHP Filtration of in-house prepared CaCO 3 NPs Drilling fluid density and ph Rheology behavior of NP-based fluid Invert emulsion drilling fluid API fluid loss characterization using other NPs Summary of the API fluid loss study of different NPs in Invert emulsion CHAPTER FIVE: MODELLING LTLP API filtration model using Darcy s law NP based fluid transport using Stoke-Einstein equation Rheology model of NP-based fluid CHAPTER SIX: CONCLUSIONS, CONTRIBUTIONS TO KNOWLEDGE AND RECOMMENDATIONS Conclusions Original contributions to knowledge Recommendations for future research viii

9 REFERENCES APPENDIX A: CLASSIFICATION OF LOST-CIRCULATION ZONES 172 APPENDIX B: LOST CIRCULATION MATERIALS SIZE SELECTION METHODS..173 APPENDIX C: DIFFUSION COEFFICIENT AND PECLET NUMBER 174 ix

10 List of Tables Table 2.1: Comparative cost analysis study of NP-based drilling mud...33 Table 3.1: Compositions of the invert emulsion and water based muds employed in this work...48 Table 4.1: API LTLP loss of drilling fluid in the presence and abscense of 1 wt% commercial Fe 2 O 3 NPs. NPs were thoroughly mixed with the invert emulsion drilling fluid. No LCMs added to both samples...73 Table 4.2: Comparative study of API LTLP fluid loss of drilling fluids with 1.6 wt% conventional Gilsonite LCM, and 1 wt% in-situ and ex-situ prepared NPs...74 Table 4.3: API LTLP fluid loss comparing drilling fluid and drilling fluid with Gilsonite LCM as base cases with drilling fluid samples containing the in-house prepared Fe(OH) 3 NPs only...78 Table 4.4: ICP results of the filtrate collected following API LTLP to determine the Ca and Fe content...79 Table 4.5: HTHP filtration property of different drilling fluid samples...81 Table 4.6: Effect of temperature and pressure on mud cake thickness...82 Table 4.7: HTHP Fluid loss of different drilling fluid samples using engineered NPs only...82 Table 4.8: Effect of shearing effect on LTLP fluid loss control...84 Table 4.9: Effect of organophillic clays on LTLP fluid loss control...85 Table 4.10:Effect of Oil: Water ratio on Fluid loss Control when using LCM...87 Table 4.11:Effect of Oil: Water ratio on Fluid loss Control when using NPs...87 Table 4.12:Density and ph measurements of drilling fluid samples with LCM and Fe(OH) 3 NPs...93 Table 4.13:Co-efficient of friction (CoF) of drilling mud samples...94 Table 4.14:Coefficient of friction (CoF) and % torque reduction in the presence and absence of NaCl salt in the invert emulsion drilling fluid...96 Table 4.15:Effect of ex situ and in situ prepared Fe(OH) 3 NPs on the performance of three different invert emulsion samples of drilling fluids provided by three different suppliers. Concentration of NPs 1 wt%, composition of invert emulsion: (90:10) oil:water (v/v)...98 Table 4.16:API LTLP WBM fluid loss with and without NPs Table 4.17:Microtox bioassay of Fe(OH) 3 NPs Table 4.18:API LTLP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing the in-house prepared CaCO 3 NPs using reaction-2 (R2) Table 4.19:API LTLP fluid loss comparing water based drilling fluid as base cases with water based drilling fluid samples containing the in-house prepared CaCO 3 NPs by reaction-2 (R2) x

11 Table 4.20:API LTLP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing the in-house prepared CaCO 3 NPs using reaction-5 (R5) Table 4.21:HTHP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing the in-house prepared CaCO 3 NPs using reaction-2 (R2) Table 4.22:HTHP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing the in-house prepared CaCO 3 NPs using reaction-5 (R5) Table 4.23:Density and ph measurements of drilling fluid samples with CaCO 3 NPs Table 4.24:Co-efficient of friction of invert emulsion drilling fluid samples Table 4.25:API LTLP Fluid loss using BaSO 4 and FeS NPs based invert emulsion Table 5.1: Permeability reduction of mud cake in the presence and absence of NPs. (R2) and (R5) refer to the raction used to prepare the CaCO 3 NPs per Section Table 5.2: Experimental and Bingham Plastic viscosity and Yield point Table B.1: Lost circulation materials selection methods Table C.1: Effect of particle sizes of DF (d p =2-200 μm in DF) on Peclet number which is a control sample of Fe(OH) 3 NP-based fluid Table C.2: Effect of Fe(OH) 3 NPs size in DF ranges from μm (1-300 nm) on Peclet number Table C.3:Effect of particle sizes of DF (d p =2-200 μm in DF) on Peclet number which is a control sample of CaCO 3 NP-based fluid Table C.4:Effect of CaCO 3 NPs size in DF ranges from μm (1-300 nm) on Peclet number xi

12 List of Figures Figure 1.1: Schematics showing a) fluid loss control using NPs along with LCM, mechanism of pore throat blocking by b) plugging and sealing, c) bridging and mud flow restriction by NPs only, and d) fluid loss using conventional LCM...3 Figure 2.1: Drilling mud circulation down the drill pipe... 9 Figure 2.2: Drilled fines and fluid particles invasion into the formation...14 Figure 2.3: Drilling fluid loss into the formation...15 Figure 2.4: Basic units of clay minerals and the silica and alumina sheets Figure 2.5: Schematic representation of Montmorillonite clay (bentonite) Structure...17 Figure 2.6: Schematic representation of the fixed and diffused double layer near a clay surface...19 Figure 2.7: Particle size scale Figure 2.8: Pore throat sizes in rocks Figure 2.9: Surface area to volume ratio of same volume of materials Figure 2.10: Schematic representation of NPs in invert emulsion fluid Figure 2.11: A characteristic filtration plot of drilling fluid during drilling...38 Figure 2.12: Three Types of Filtration Curves Figure 2.13: Bridging effects with varying particles diameter in pore throat Figure 2.14: Overview of Filtration mechanisms...45 Figure 2.15: Effect of particle diameter on collision probability Figure 2.16: NPs plugging probability during drilling...47 Figure 3.1: Schematic representation of the ex-situ method for NP-based drilling fluid preparation...50 Figure 3.2: Schematic representation of in-situ NP-based drilling fluid...53 Figure 3.3: Schematic of In-situ prepared CaCO 3 NPs-based drilling fluid using CO Figure 3.4: Drilling fluid loss apparatus for a) LTLP and b) HTHP tests Figure 3.5: Fann Model 35A viscometer for measuring viscosity...60 Figure 3.6: OFITE drilling fluid lubricity tester...62 Figure 4.1: X-ray diffraction pattern for the ex-situ prepared iron-based NPs Figure 4.2: X-ray diffraction pattern of ex-situ prepared Fe(OH) 3 NPs collected on the filter paper...65 Figure 4.3: Particle size distribution histogram of water droplet obtained from a water-in-oil emulsion by dispersing water into base-oil with the aid of primary emulsifier...66 Figure 4.4 : TEM photographs and corresponding particle size distribution histograms of ex-situ prepared Fe(OH) 3 NPs in the range between a) nm and b) 1-30 nm Figure 4.5: SEM Images at 48x magnification of mud cakes following API LTLP filtration tests a) without NPs, b) with in-situ NPs (90/10 oil/water invert emulsion mud and 1 wt% Fe(OH) 3 NPs)...69 xii

13 Figure 4.6: Elements contained in mud cake a) without NPs, b) with Fe(OH) 3 NPs as per EDX analysis...70 Figure 4.7: Photos comparing NP-based and original invert emulsion drilling fluids (Invert emulsion (90 vol. oil/10 vol. water); 1 wt% Fe(OH) 3 in-situ prepared NPs)...71 Figure 4.8: Mud cake of drilling fluid with commercial NPs and without NPs Figure 4.9: Mud Cakes with thickness of a) DF only, b) DF+LCM, c) DF +LCM with 1 wt % ex-situ NPs, and d) DF+LCM with 1 wt % in-situ NPs...77 Figure 4.10: Mud Cakes of a) DF only, b) DF+LCM, c) DF with 1wt % ex-situ NPs and d) DF with 1wt % in-situ NPs Figure 4.11: Filter cakes obtained following API HTHP tests on invert emulsion drilling fluids with and without Fe(OH) 3 NPs and Gilsonite LCMs...82 Figure 4.12: Mud cakes obtained following API HTHP tests on invert emulsion drilling fluids with in-house prepared NPs only Figure 4.13: Quality of unblended and blended mud cake Figure 4.14: Rheological behavior of drilling fluid containing a) LCM together with in-house prepared 1 wt% Fe(OH) 3 NPs, b) 1 wt% Fe(OH) 3 NPs no LCMs Figure 4.15: Gel strength behavior of drilling fluid a) with LCM and NPs together ex-situ and in- situ method b) in the absence of LCM, with NPs only ex-situ and insitu method...91 Figure 4.16: Shelf life of drilling fluid samples in terms of rheology behavior...92 Figure 4.17: Aging effect of drilling fluid samples in terms of gel strength Behavior Figure 4.18: Apparent viscosity at 600 rpm of 3 invert emulsion drilling fluids provided by different supplies in the presence and absence of 1 wt% Fe(OH) 3 NPs. Composition of invert emulsion: (90:10) oil: water (v/v)...99 Figure 4.19: X-ray diffraction pattern of ex-situ prepared CaCO 3 NPs starting from the aqueous precursor salts Figure 4.20 : TEM photographs of ex-situ CaCO 3 NPs at two different magnifications Figure 4.21 : Particle size distributions of ex-situ prepared CaCO 3 NPs Figure 4.22 : SEM images of mud cake a&b) without NPs ;c&d) in-situ CaCO 3 NPs (R2); and e&f) in-situ CaCO 3 NPs (R5) Figure 4.23 : Elements containing mud cake a) without NPs,b) with In-situ NPs (R2) and c) with in-situ NPs (R5) from EDX data Figure 4.24 : Available pore openings (nm) in mud cake of DF without NPs Figure 4.25: Particle size distribution of in-situ CaCO 3 NPs, prepared by reactions (R2) and (R5), in the mud cake xiii

14 Figure 4.27: Rheological behavior of invert emulsion drilling in presence and absence of 4 wt% in-house prepared CaCO 3 NPs. No LCMs added Figure 4.28: Gel strength behavior of invert emulsion drilling fluid in presence and absence of 4 wt% in-house prepared CaCO 3 NPs. No LCMs added Figure 4.29: LPLT fluid loss behavior of different ex-situ NPs in invert emulsion drilling fluid Figure 4.30: LPLT fluid loss behavior of different in-situ NPs in invert emulsion drilling fluid Figure 4.31: Different NPs and NPs-containing drilling fluid stability Evaluation Figure 4.32: NPs-containing drilling fluid filter cakes (thickness <1 mm) Figure 5.1: Filtrate volume variation with square root of time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs Figure 5.2: Filtrate volume variation with square root of time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs Figure 5.3: Mud cake permeability variation with time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs Figure 5.4: Mud cake permeability variation with time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs Figure 5.5: Comparison of permeate (filtrate) flux with time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs Figure 5.6: Comparison of permeate (filtrate) flux with time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs Figure 5.7: Variation of Mud cake thickness with time for NP-based fluid Figure 5.8: Effect of particle sizes of DF (dp =2-200 μm in DF) on Peclet Number Figure 5.9: Effect of Fe(OH) 3 and CaCO 3 NPs size in DF ranges from μm (1-300 nm) on Peclet number Figure 5.10: Bingham Plastic model for Fe(OH) 3 NP-based drilling fluid Figure 5.11: Bingham Plastic model for CaCO 3 NP-based drilling fluid (R5) and (R2) refer to the reaction used to prepare the particles as detailed in section xiv

15 List of Symbols, Abbreviations and Nomenclature Symbol Definition A cross sectional area of the filter cake under static filtration,cm 2 A r Hamaker constant which has values generally in order of Jouls C NP Concentration of nanoparticles,molarity D BM Brownian diffusion coefficient, cm 2 /sec D NP diffusion co-efficient of nanoparticles,cm 2 /sec Van der Waals potential energy, Jouls E vdw J total flux, moles/cm 2 -s J Diffusion diffusion flux of NPs, moles/cm 2 -s J advection advection flux, moles/cm 2 -s M Molarity, (mol/l) N Pe Q c Q f R rotor speed (rpm) Peclet number volumes of the filter (cm 3 ) cake at a given time, (cm 3 /min) volume of filtrate in (cm 3 ) at a given time,(cm 3 /min) radius of the particle,cm S filter effective surface area = cm 2 T U V t V absolute temperature,k characteristic velocity of flow,cm/sec sedimentation velocity of particles in dilute suspension,cm/sec volume of permeate or filtrate in ml Y p yield point (lb f /100ft 2 ) a c a p d g d p d NP h h mc k k B collector radius or collector characteristics length,cm particle radius,cm diameters of the grains,cm diameters of the particles,cm nanoparticles diameter,cm distance between the particles (nm) thickness of the mud cake at a given time, cm permeability in darcies Boltzman constant= 1.38X10-23 J/K xv

16 r t P ratio between the volume of the filter cake at a given time to the volume of time in sec differential pressure in atmospheres,(atm) Shear stress,pa Yield stress,pa Shear rate,sec -1 µ dynamic viscosity of the liquid,cp density of the particles,g/cm 3 φ μ p density of liquid, g/cm 3 collision probability porosity of medium plastic viscosity (cp) viscometer dial reading ( o ) dial readings at 600 rpm ϴ 600 ϴ 300 Abbreviation AADE AEUB API DF EDX HTHP IF-WS 2 LCMs LC 50 LTLP NPs OBM SEM TEM WBM XRD nm dial readings at 300 rpm The American Association of Drilling Engineers ALBERTA ENERGY AND UTILITIES BOARD American Petroleum Institute Drilling Fluids Energy dispersive X-ray High Temperature and High Pressure Inorganic fullerene-like disulfide tungsten Lost circulation materials Lethal concentration used as an indicator of the toxicity of a compound Low Temperature and Low Pressure Nanoparticles Oil based mud Scanning electron microscopy Transmission Electron microscopy Water based mud X-ray diffraction analysis nanometer xvi

17 Chapter One: Introduction 1.1 Problem statement and significance of the research The success of any well-drilling operation depends on many factors and one of the most important is the drilling fluid. Drilling fluids, a.k.a. drilling mud, are circulated from the surface into the drill string and subsequently introduced to the bottom of the borehole as fluid spray out of drill bit nozzles and back to surface via the annulus between the drill string and the well hole. Drilling fluids cool down and lubricate the drill bit, remove cuttings from the hole, prevent formation damage, suspend cuttings and weighting materials when circulation is stopped, and cake off the permeable formation by retarding the passage of fluid into the formation (ASME, 2005). However drilling operations face great technical challenges with drilling fluid loss being the most notable of them. Drilling fluid loss is defined as the partial or complete loss of fluid during drilling. Loss of fluid, in turn, impacts the cost of drilling. The cost of the drilling fluid system often represents one of the single peak capital expenditure in drilling a new well and can bump up swiftly when drilling deep holes, complex formations or in remote locations (Abdo and Haneef, 2010). According to a recent in-house estimate, fluid losses during drilling costs the industry around $800 million per year. Regardless of the real number of the economic impact in this segment, it represents a very large portion of the total non-productive expense for drilling a well and therefore fluid loss/circulation loss issues have intensified than past. Provided that the overall economics prove to be favorable, a more efficient route needs to be addressed during drilling by eliminating losses of fluid or at least controlling them to the extent that drilling can continue uninterrupted (Fraser et al., 2003). Therefore, drilling fluids are typically formulated with loss circulation materials (LCMs). The primary function of LCM is to plug the zone of loss in the formation, away from the borehole face so that subsequent operation will not suffer additional fluids losses. LCM forms a barrier which limits the amount of drilling fluid penetrating the formation and prevents loss (Chenevert and Sharma, 2009). Most of the new lost circulation materials have been developed in the past 10 years (McLean et al., 1

18 2010). However, using these existing lost circulation materials are not found so effective to serve their primary goals of curing fluid loss. Current experience shows that it is often impossible to reduce fluid loss successfully with these micro and macro type fluid loss additives due to their physio-chemical and mechanical characteristics, e.g. size, surface charge, solvation and mechanical resistance etc., thus raising the economic consequences of non-productive drilling time (Chenevert and Sharma, 2009; Fraser et al., 2003). For example, LCM with diameters in the range of µm may play an important role when the cause of fluid loss occurs in 0.1 µm-1 mm porous formation. In practice, however, the size of pore opening in shales that may cause fluid loss varies in the range of 10 nm-0.1 µm. Therefore, nanoparticles (NPs) as a loss circulation material could fulfill the specific requirements by virtue of their size domain, hydrodynamic properties and interaction potential with the formation (Amanullah et al., 2011; Srivatsa, 2010; Abdo and Haneef, 2010). Alternatively, NPs can help bridging empty gaps between macro LCMs, and therefore, providing an effective seal to formation with larger pore throat size. The plugging of pore throats by the use of nanoparticles is a new approach for controlling fluid penetration into shales and could significantly reduce wellbore instability problems (Sensoy,2009). Pore space is defined as a collection of channels through which fluid can flow. The effective width of such a channel varies along its length. Pore bodies are wide portions and pore openings or pore throats are the relatively narrow portions that separate these pore bodies (Nimmo,2004). NPs thus could be a promising option for the development of drilling fluids to provide the effective sealing, filling and cementing properties resulting in the reduction of porosity, permeability of the wellbore formations and thereby prevent the loss of fluid. This is not viewed as formation damage, since these particles can be used during the drilling operation far from reservoir formation. These particles are ultrafine in nature and possess very high specific surface area of interactions. By adding small quantities of NPs in drilling fluid ensuring mixing at the molecular level, wrapping and interpenetrating network structures to achieve this new class fluid. By forming a thin, low permeability filter cake which seals pores and other openings in the formations 2

19 Mud flow Mud flow penetrated by the drill bit as shown in Figure 1.1, NP-based drilling fluid could also prevent unwanted influxes of formation fluids into the borehole from permeable rocks penetrated during drilling. Kanj et al. (2009) suggested that small particles of high concentrations might bridge across the pore throat. Again smaller particles aggregate around larger ones to fill the tinier spaces and hence effectively plug the pore opening spaces. In water-based drilling fluids, NPs of mixed metal hydroxides (MMH) have already been used to replace polymers as viscosity modifying agents (Agarwal et al., 2009). NPs of MMH work as a bridging material, which promotes aggregation between the platelets of bentonite/montmorillonite clay to form a gel structure. Particle size and surface characteristics of NPs can also be easily manipulated in water-in-oil emulsions in a similar fashion to those formed in (w/o) microemulsions (Husein and Nassar, 2007a&b). a) b) - -- No/ Partial fluid loss using NPs c) d) Legend Fluid loss without using NPs LCM Nanoparticles Figure 1.1: Schematics showing a) fluid loss control using NPs along with LCM, mechanism of pore throat blocking by b) plugging and sealing, c) bridging and mud flow restriction by NPs only, and d) fluid loss using conventional LCM. 3

20 In light of the aforementioned functional properties of NPs, our approach consisted of developing tailor made NP-based drilling fluid which would best interact with the rest of the drilling fluid components as well as the formation and reduce fluid loss during drilling, meanwhile optimize the functionality of the drilling fluid over a wide range of conditions; including temperature, pressure, drilling environment and formation. Moreover, the proposed NP-based fluid would reduce the total solids and/or chemical additives to the typical drilling fluid leading to an overall lower fluid cost (Amanullah et al., 2011; Abdo and Haneef, 2010; Mokhatab et al., 2006). 1.2 Research Objectives This research investigates the role of in-house prepared dispersed NPs in reducing drilling fluid loss and the impact their existence might have on drilling fluid characteristics; including viscosity, density, ph and lubricity. The hypothesis is that dispersed NPs in drilling fluids are better able to conceal pores as a result of a fine balance between particle dispersion and deposition onto micro and nanopores. As shown in Figure1.1, the NPs will selectively deposit over fine pores or will conceal gaps between already deposited clay particles. Such research will be the key to unlocking the problems of inter channel pore clogging of formation (keeps away the migration of drilled fines entering the pores), reduce fluid loss and improve the productivity of the wells. In order to meet the challenge of improving the properties of drilling fluid, this research has been undertaken with several parallel developments of NPs. These welldispersed NPs employed in fluid formulation are unique and have high surface energy, which can readily attach with other additives and create a barrier to lower the fluid loss in an efficient manner. All this needs to be achieved without introducing fundamental property change in the drilling fluid. The overall goals of this research are therefore, to develop a method for in-house preparation of NPs, which can be easily mixed and stabilized in water as well as invert emulsion based drilling fluids, and to evaluate the performance of the final product. Low aromatic hydrotreated oil was selected, since such a base oil makes the invert emulsion fluid more environmentally friendly. Accordingly, the objectives of this research are summarized as follows: 4

21 1) In-house synthesis and characterization of NPs and the preparation of stable NPbased drilling fluids. 2) Study the impact of the presence of the NPs on drilling fluid loss using API lowtemperature-low-pressure (LTLP) test as well as the high-temperature-high-pressure (HTHP) test. Both oil-based and water-based drilling fluids were tested. 3) Detail the effect of NPs on drilling fluid properties; including viscosity, density, ph and lubricity. 4) Investigate how the behavior of NPs in the drilling fluid is affected by other components of the drilling mud. 5) Investigate the possibility of eliminating other loss circulation material (LCM) additives as a result of NPs addition, which may lead to an overall drilling fluid price reduction. The project has been divided into four main phases: Phase one: In-house, in-situ and ex-situ, preparation of the dispersed Fe(OH) 3(s) NPs in the drilling fluid and their characterization: 1. NPs of Fe(OH) 3(s) were successfully prepared in-house. Two schemes were used. Ex-situ scheme, where the NPs were prepared by aqueous reactions of the precursor salts and the product NPs mixed with the drilling fluid. In-situ scheme, where the aqueous precursors were directly added to the drilling fluids, and the NPs nucleated within the drilling fluid. 2. Characterization of the ex-situ prepared particles, which included particle identification using X-ray diffraction (XRD), and determination of particle size distribution using transmission electron microscopy (TEM). 3. Characterization of the in-situ prepared particles followed their collection on the filter cake; including particle identification using energy-dispersive X-ray spectroscopy (EDX), and determination of particle size distribution using scanning electron microscope (SEM). 5

22 4. Study the fluid loss of NP-based drilling fluid following API low temperature and low pressure (LTLP) and high temperature and high pressure (HTHP) filter press protocols. Also, determining the thickness of the resultant filter cake, since thin filter cake prevents stuck pipe during drilling. 5. Characterize the NP-based drilling fluid in terms of its viscosity, density, ph and lubricity. Phase two: In-house, in-situ and ex-situ, preparation of CaCO 3(s) NPs in the drilling fluid and their characterization: 1. NPs of CaCO 3(s) were prepared in drilling fluid. Three schemes were used in this case. Ex-situ scheme, where the NPs were prepared by aqueous reactions of the precursor salts and the product NPs mixed with the drilling fluid. Two schemes of in-situ preparation of the CaCO 3(s) NPs were adopted. In one scheme the aqueous precursor salts were directly added to the drilling fluid, and the NPs nucleated in the drilling fluid, while in the other scheme an aqueous calcium salt was added to the drilling fluid followed by CO 2(g) bubbling. This scheme of in-situ preparation of the CaCO 3(s) particles helps creating the particles in the drilling fluid while in the formation, and therefore, prevents any changes to the nature of particles during drilling. 2. Characterization of the ex-situ prepared particles included particle identification using X-ray diffraction (XRD), and particle size determination using transmission electron microscopy (TEM). 3. Characterization of the in-situ prepared particles followed after their collection on the filter cake; including particle identification using energy-dispersive X-ray spectroscopy (EDX), and determination of particle size distribution using scanning electron microscope (SEM). 4. Study the fluid loss of NP-based drilling fluid following API low pressure and low temperature (LTLP) and high pressure and high temperature (HTHP) filter press protocols. Also, determining the thickness of the resultant filter cake, since thin filter cake prevents stuck pipe during drilling. 6

23 5. Characterize the NP-based drilling fluid in terms of its viscosity, density, ph and lubricity. Phase three: In-house, in-situ and ex-situ, preparation of BaSO 4(s) and FeS (s) NPs in the drilling fluid by two methods and characterize their LTLP fluid loss property only. 1. NPs of BaSO 4(s) and FeS (s) were successfully prepared in-house. Two schemes were used. Ex-situ scheme, where the NPs were prepared by aqueous reactions of the precursor salts and the product NPs mixed with the drilling fluid. In-situ scheme, where the aqueous precursors were directly added to the drilling fluids, and the NPs nucleated within the drilling fluid. 2. Study only the fluid loss of NP-based drilling fluid following API low pressure and low temperature (LTLP) protocol. Phase four: This phase involves developing a mathematical model to describe fluid loss and cake growth using NPs as a lost circulation material. 1.3 Organization of the Thesis This thesis is organized into six chapters. The first chapter presents a brief scope of the research and its significance. General overview of lost circulation material used in drilling fluid and challenges faced while drilling is introduced. Introduction of NPs as new lost circulation materials and its potential application in fluid loss reduction are explained. Chapter two presents an extensive literature review on drilling fluids, nanoparticles (NPs), NP-based drilling fluid, filtration mechanism and governing equation used in filtration process. In Chapter three, experimental methods used for in-house NPs preparation (ex-situ and in-situ) is explained together with methods used to characterize the NPs and the NPbased drilling fluids. 7

24 Results obtained from the experimental works are discussed and analyzed in detail in Chapter four. NP-based fluids are compared with the base fluid in terms of fluid loss at LTLP and HTHP conditions, density, viscosity and lubricity. TEM and XRD analyses reveal the ex-situ prepared NPs characterization, whereas SEM images of mud cake unveiled the characteristics of in-situ prepared NPs. Chapter five deals with modeling of NP-based fluid filtration performance through porous media (API filter paper) at LTLP condition. The cake thickness growth model at 30-min time period are proposed. Also Bingham plastic model are used to describe the rheological behavior of NP based fluid. Chapter six presents the conclusion drawn from the work, original contributions to knowledge and recommendation for future research to extend this study. 8

25 Chapter Two: Literature Review This chapter reviews the drilling fluid general functions and their related challenges, clay chemistry, nanoparticles properties and previous experimental studies of drilling fluid properties using lost circulation materials and nanoparticles with particular reference to those which are directly relevant to the subject under investigation. 2.1 Introduction Drilling fluids are composed of a number of liquids and gaseous fluids and mixtures of fluids and solids (Vasii,2008). A drilling fluid is typically used in a drilling operation in which that fluid is circulated or pumped from the surface, down the drill string and is subsequently introduced to the bottom of the bore hole as it squirts out of nozzles on the drill bit and back to the surface via the annulus as shown in Figure 2.1. Figure 2.1: Drilling mud circulation down the drill pipe (courtesy of Payson Petroleum, reprinted by permission). 9

26 Large pumps are used to circulate the mud on a drilling rig. They pick up the mud from the mud tank and force it into and down the drill string and to the bit. Typical pressure at the exit of these pumps can be as high as 7,500 psi (52,000 kpa) (Dyke and Baker,1998). At the bit the mud jet out of the bit nozzles to move cuttings away from the bit. The mud then moves back up the hole to the surface. The mud picks up cutting made by the bit and carries them as it returns to the surface. The mud and cuttings return to the surface in the annulus between the outside of the drill string and the inside hole. At the surface, the mud and cuttings leave the well through a side outlet with a pipe called the mud return line. At the end of the flow line, mud and cuttings fall on to a vibrating screen (or sieve) named as shale shakers which is the device on the rig for removing drilled solids from the mud. A wire-cloth screen vibrates while the drilling fluid flows on top of it. The liquid phase of the mud and solids smaller than the 200 wire mesh (< 74 μm) pass through the screen and go back to the pits while larger solids are retained on the screen and eventually discarded (ASME, 2005; AADE,1999; Chilingarian and Vorabutr, 1983). 2.2 Drilling fluid Classification Drilling fluids are typically classified according to their base material into water-based muds and oil-based muds. In water-based muds (WBM), water is the continuous phase and solid particles are suspended in water or brine. Oil-based muds (OBM) are exactly the opposite. Oil is the continuous phase and solid particles are suspended in oil, water or brine is emulsified in the oil by surfactants (ASME, 2005; Srivatsa, 2010). Oil based drilling fluids have definite advantages when compared to water based fluids. These include maintaining stable rheology and filtration control for extended periods of time and increased lubricity. In addition, oil base drilling fluids can be used to drill through most troublesome shale formations due to their inherent inhibitive nature and temperature stability (Mas et al.,1999). The filtrate from a water based mud may cause clays in the formation to swell and disperse, which can cause severe damage to well productivity. Many instances are on record where a formation of proved productivity has been exposed to water or water based mud and consequently production was greatly 10

27 decreased or in some cases completely lost (Sharma and Jiao, 1992; Tovar et al., 1994; Argiller et al., 1999). A study has shown that drilling fluid loss costs the oil and gas industry over $800 million per year (Fraser et al., 2003). An attempt has therefore been made to develop an invert emulsion drilling fluid (water-in-oil) which would mitigate the problem. Oil alone does not have the ability to form a filter cake on the wall of the bore hole but mud additives are used to restrict the loss of fluid into permeable formations. The filter cake or sheath is water impermeable and substantially oil impermeable so that virtually none of the fluid base oil or the water in the fluid is lost into the formation. Even though the filtrate is small amount of oil, fluid which may penetrate the filter cake does not substantially affect formation permeability (Baker 1995; 2006). Therefore this oil based system has been directed towards modification by obtaining satisfactory suspending particles and forming thin filter cake characteristics. These have resulted in the development of the emulsification of water or water based mud in the oil. The use of invert emulsion oil mud has greatly increased over the past few years due to the demands of drilling deeper and more difficult wells. 2.3 Functions of Drilling Fluids A properly designed and maintained drilling fluid system performs the essential functions. A drilling fluid is used to carry out the following functions (ASME, 2005; Chilingarian and Vorabutr, 1983): a. Removal of Cuttings. Drilled cuttings are removed that results in a cleaner hole. The ability of a mud to carry cuttings to the surface depends partly on the characteristics of the mud and partly on the circulating rate in the annulus. When the pump capacity is too low to provide adequate annular velocity for cuttings removal, increasing the mud viscosity particularly the yield point may result in a cleaner hole. b. Suspension of Cuttings. Good drilling fluids have thixotropic properties that caused the solids particles, being carried to the surface, to be held in suspension when circulation is stopped. 11

28 c. Control Formation Pressure. It is a very important function of drilling fluid because it is the first line of defense against possible blowouts. d. Caking off Permeable Formations. A good drilling fluid provides filtration properties that retard the passage of fluid into the formation. In many cases it may be necessary to add fluid loss control additives to reduce the fluid loss. Ideally the muds form a thin tough filter cake across the permeable formations. This keeps the hole in stable condition. It also minimizes the quantities of mud and filtrate entering the formation. e. Cooling and Lubrication. During drilling operations, both the drill string and the bit develop heat through friction. Drilling mud helps to cool the drill string and also provides lubrication by reducing friction between drill string and borehole walls. Thus the lubricity of the mud is important. The cooling function depends upon the thermal conductivity of the mud. f. Reduce Formation Damage. Formation damage is very much tied to the filtration properties of the mud. Damage from filtrate invasion depends on the quantity of filtrate entering the formation. g. Minimize Corrosion. In water based mud corrosion is controlled by alkalinity or by addition of corrosion inhibitors. It has been found that in muds containing oil as the continuous phase, little or no corrosion occurs. 2.4 Drilling fluid related challenges Many drilling problems are due to conditions or situations that occur after drilling begins and for which the drilling fluid was not designed. Zamora et al. (2000) discussed 10 mud-related concerns. Failure to adequately address these concerns can lead to excessive well costs, unscheduled trouble time, unnecessary high-risk activities, and poor performance. Some of these problems can be solved by adding materials to the drilling fluids to adjust their properties. The top 5 mud related problems are found directly relevant to the subject under investigation and described as follows: 12

29 a. Borehole instability. Borehole instability is common problems in shale section. Any formation can collapse if the mud weight is not appropriate to control it. To minimize its borehole instability, proper mud characteristics (mud viscosity, drag and torque reduction and fluid loss) are important. b. Stuck pipe. During drilling oil and gas wells, drill string consisting of pipes and collars are used to drill the formation. Filtrates invade permeable zones and filter cakes are deposited on the wall of holes. A portion of the drill string is then embedded in the mud cake on the walls of the borehole. When the drill string is no longer free to move up, down or rotate, the drill pipe is supposed to stuck. This problem is generally caused by the drill pipe sticking to the mud cake on the wall of the wellbore due to filtrate loss in the wall of the well and the formation of a thick filter cake or due to the cuttings backing into the wellbore as drilling fluid circulation is stopped. The pull force to free the pipe is a function to the differential pressure, co-efficient of friction and the total contact area of the pipe on the hole wall. The co-efficient of friction (CoF) is one of the important functions of drilling fluid. An oil-based drilling fluid has co-efficient of friction (CoF) of 0.10 or less (metal to metal) (Chang et al.,2011). In comparison, water has a CoF of 0.34 and the CoF of water-base drilling fluids typically ranges between 0.2 and 0.5 (Chang et al., 2011). It is known that presence of ordinary materials in drilling mud can cause increased viscosity and mud weight (Dickerson and Rayborn, 1992). This high mud weight can cause damage to sub-surface formations, plugging of production zones, hole erosion, decreased penetration rate, pipe failures, stuck pipe and lost circulation (Amoco, 1996; BHI, 1998; Reid et al., 2000; Njobuenwu and Nna, 2005). So in order to decrease probability of stuck pipe it is necessary to design new materials which do not increase viscosity and mud weight (Paiaman and Al-Anazi, 2008). To minimize differential sticking, maintaining proper mud characteristics (fluid loss, mud density, lubricity, low solid in mud) is very important. 13

30 c. Salt section hole enlargement. Salt sections may be eroded by the drilling fluid, which causes hole enlargement. To avoid this problem, salt saturated mud system is prepared for drilling through the salt bed. d. Formation damage. Formation damage is generally a reduction in permeability near the wellbore with porosity reduction. This represents a positive skin effect. Almost every field operation is a potential source of damage to well productivity. Diagnosis of formation damage problems has led to the conclusion that formation damage is usually associated with either the movement and bridging of fine solids in the producing horizons and the penetration of drilling fluid particles into formation which cause pore plugging of the porous media. The fine solids may be introduced from wellbore fluids or generated in situ by the interaction of invading fluids with rock minerals or formation fluids. There are a number of ways that drilling fluid filtrate might interact with the formation to cause permeability damage. Some of these have been investigated in published papers (Al-Hitti et al.,2005; Zamura et al.,2000; Chilingarian and Vorabutr,1983). Figure 2.2 shows the blockage of the reservoir-rock pore spaces caused by the fine solids in the mud filtrate or solids dislodged by the filtrate within the rock matrix. Figure 2.2: Drilled fines and fluid particles invasion into the formation (Zwager, 2007). 14

31 In addition to pore throat blockage, the formation damage also can be happened due to clay-particle swelling or dispersion, scale and precipitation, emulsion blockage and water blockage (Peng, 1990). e. Lost circulation. Lost circulation means the uncontrolled flow of substantial amount of drilling mud to an encountered formation. This can be a partial lost, some returns to surface or a complete loss with no returns to the surface. Lost circulation can occur in several types of formation, including highly permeable formations, fractured formations and cavernous zones (Chilingarian and Vorabutr, 1983). Different lost circulation zones are described in Appendix A. Lost circulation occurs when hydrostatic pressure of mud exceeds the breaking strength of the formation and that creates cracks along which the fluid will flow. Fluid will flow in large fracture greater than 100 microns. In practice, the size of pore opening of shales that can cause lost circulation is in the range of 10 nm-0.1 microns (Sensoy et al.,2009). Overbalance pressures in excess of about 7000 kpa (1000 psi) are generally considered to be severe and may cause serious losses of filtrate and associated solids to the formation (Bennion et al.,1997). Figure 2.3 shows the fluid loss during drilling. Figure 2.3: Drilling fluid loss into the formation (courtesy of nfluids Inc, reprinted by permission). 15

32 Lost circulation materials can be added to mud to bridge or deposit a material where the drilling fluid being lost to the formation. To minimize lost circulation, proper mud design (usage of suitable lost circulation materials, maintan proper mud weight, maintain adequate hole cleaning) is necessary. In addition, the appropriate size distribution of bridging materials to create an effective sealing of impermeable filter cake which deposits very rapidly on the face of the formation and thereby inhibiting continual losses of drilled fluid (Al-Hitti et al., 2005). 2.5 Clay Chemistry used in drilling fluids Clays are naturally occurring materials mainly composed of hydrous aluminum silicates and typically formed over long periods of time by chemical weathering of rocks that contain silicate (Deriszadeh, 2012). The colloid chemistry of clays to drilling fluid design is of value at the present and will continue to be so in the future (Browning and Perricone,1963). Clays are usually microscopic in size (typically < 2 µm) and also occur as submicroscopic particles. Pauling (1930) studied the crystalline structure of clays. It is also pointed out by Grim (1953) that most of the clay minerals have two structural units that are the building blocks of their atomic lattices. Silica tetrahedron is the first unit and alumina octahedral coordination which is the second unit as shown in Figure 2.4. These basic sheets are stacked together to form different clay minerals. Figure 2.4: Basic units of clay minerals and the silica and alumina sheets (Mitchell and Soga, 2005). 16

33 Clays are the major constituents of shale and due to their special characteristics they play a crucial role in the mechanical and chemical properties of shale (Santamarina et al., 2002). Clays are also the major constituent in drilling fluid and provide the fluid a distinctive character. The properties exhibited by a particular drilling fluid largely depend on the origin and characteristics of the clay component present in the fluid (Maduka, 2010). Three types of clays are used in drilling fluid formulation: montmorillonite (smectite), kaolinites and illites. Among them montmorillonite, which is also known as bentonite, is the most commonly used clay because of its superior ability to swell uniformly in fresh water upon shear application resulting in a more homogeneous claywater mixture (Chilingarian and Vorabutr, 1983). Montmorillonite clay has the formula [(A) 0.3 (Al 1.3,Mg 0.7 ) (Si 4 )O 10.(OH) 2.xH 2 O] where A is an exchangeable cation, K +, Na +, or 0.5 Ca 2+. Figure 2.5 displays the structure of Montmorillonite clay minerals according to Grim (1962). According to literature, (Santamarina et al., 2002; Mitchell and Soga, 2005), bentonite has a high specific surface area of 800 m 2 /g. The diameter of bentonite platelets could vary between 2000 to A with a thickness of about 10 A bentonite platelets are bonded together by weak Van der Waals bonds. Therefore it may allow water to enter the space between the platelets (Deriszadeh, 2012). Figure 2.5: Schematic representation of Montmorillonite clay (bentonite) structure (Grim,1962). 17

34 Browning and Perricone (1963) showed the effect of ph on clay surface. ph values increment from 10.5 to 11 in the absence of deflocculates rapidly increased the system resistance to shear with time indicating an increased tendency of surface area of the clay suspension. The more stable clays system can be introduced by maintaining proper ph. Chilingarian (1952) found that hydroxyl ion (OH - ) adsorb on bentonite clay platelets increased the total negative charges on the clay sheets causing repulsion of nearby platelets (dispersed state). Figure 2.6 represents the ion exchange behavior of clay surface. A double layer occurs when counter ions are attracted to the charged surface of a particle and form a layer. The ions are held in place by Coulombic forces. A diffuse layer occurs when the electrostatic attraction between the ions in solution and the colloidal surface is counteracted by diffusion where the charge on the particle is neutralized by a swarm of ions. The net negative charge of the clay surface has the capacity to attract cations or positive charge molecules. With cation exchange may result in a well dispersed mud system and simply as a result of neutralization of negative charges on clay platelets. In such cases, plastic viscosity with decreasing internal friction and gel strength reduction may occur. Highly charged cations can impact greater attraction of clay platelets allowing lower fluid loss and form a filter cake having very low permeability. Cations held by clays can be replaced by other cations. This means they are exchangeable. Hanshaw (1963) showed that the order of cation exchange selectively is dependent upon whether clay is dispersed or compacted. In fact, the negative charge on particles is compensated by attraction of cations on the surface. In the case of bentonite high concentration of cations would also occur inside the particles as the spacing between platelets of each particle could vary due to this presence of weak van der Waals forces among the adjacent platelets in each particle. A small fraction of cations on the surface of particles develop the inner compact layer commonly referred to as the immobile Stern layer (Mitchell and Soga 2005; Deriszadeh, 2012). In fact, some researchers concentrated on the fluid and ionic flows through micro pores and the interparticle space of the clays (Mitchell and Greenberg, 1973; Moyne and Murad, 2002; Smith, 2005; Sherwood, 1994). 18

35 Figure 2.6: Schematic representation of the fixed and diffused double layer near a clay surface (Dampier, 2004). The drilling fluid is a colloidal clay system though its consistency is critical. It must be fluid enough to be pumped and thick enough to keep the cuttings suspended. In order to prevent the loss of fluid, it is necessary to minimize the amount of fluid entering the porous formations. The colloidal clay in drilling mud contributes to the filter cake building up against the wellbore. When a suspension of a finely divided precipitate is filtered, the filtration is slow because the particles pack tightly on the filter. The filter cake deposited by a coarser precipitate of larger particles is less dense and more porous. The characteristics of the filter cake formed depend on the degree of peptization or flocculation of the suspension (Zakaria et al.,2012). Stable (peptized) suspensions form dense, compact sediments while flocculated suspensions form more voluminous sediments. The filter cake formed from a stable suspension will be dense and relatively impenetrable in comparison to that formed from a flocculated suspension. Thus a stable suspension has more effective plastering characteristics (Baker, 2006; Schmidt et al., 1987). Chemical changes in clay minerals use certain additives in order to modify the properties of drilling fluid. These additives could result in a safe and speedy drilling with a maximum productive capacity after completion of a well. 19

36 2.6 Nanoparticles Nanoparticles are defined as particulate dispersions or solid particles with a size in the range of nm (Nabhani and Emami,2012; Zakaria et al.,2011). Using nanoparticles in drilling fluid provide a new era in drilling industry. Amanullah and Al-Tahini (2010) defined nano fluids as any fluids (drilling fluids, drill-in-fluids, etc.) used in the exploitation of oil and gas that contain at least one additive with particle size in the range of nm. They also classified nano fluids as simple nano fluids and advanced nano fluids. Simple nano fluids contain nano particles of only one dimension, whereas advanced nano fluids are ones with multiple nanosize additives. Commonly used drilling fluid additives such as bentonite and barite in the conventional drilling fluids have much larger particle diameters, ranging between 100 nm to more than 100 microns (Srivatsa, 2010; Abrams, 1977; Cai et al., 2012). Figure 2.7 shows a scale of typical particle size ranges. There have been several methods for the selection of the lost circulation materials, which are based on the size for the purpose of keeping mud loss at minimum and given in Appendix B. Figure 2.7: Particle size scale (adapted from Abrams (1977) and Sensoy et al., (2009)). In general pore-throat sizes (diameters) are greater than 2 μm in conventional reservoir rocks, range from about 0.03 to 2 µm in tight-gas sandstones, and range from to 0.1 μm in shales (Nelson, 2009). Figure 2.7 shows the pore size connection for sandstone, tight sand and shales according to Rezaee et al.(2012). Al-Bazali et al. (2005) also reported average pore throat sizes of variety of shales in the range from 10 to 30 nm. Even though, loss in shale formations is not a big problem, nanoparticles can 20

37 be ideal additives to minimize fluid seeping into such a sensitive formation (Chenevert and Sharma, 2009). Figure 2.8: Pore throat sizes in rocks (adapted from Rezaee et al., (2012)). According to Smalley and Yakobson (1998), the laws that govern nanoscale material behave)ior are completely different than the laws governing the macro and micro-scale behavior. Nanoparticles possess very large surface area per volume as shown in Figure 2.9. Figure 2.9: Surface area to volume ratio of same volume of materials (Amanullah and Al-Tahini, 2009). 21

38 These particles are smaller than micro particles requiring a very low additive concentration and hence provide superior fluid properties at low concentrations of the additives (Amanullah and Al-abdullatif, 2010).This causes a very large potential for interaction with other matter as a function of volume. These enormous surface areas to volume dramatically increase the interaction of the nanoparticles with the matrix or surrounding fluid (Monteiro and Quintero,2012). This property of nanoparticles provide them increased interaction with reactive shale to eliminate shale-drilling mud interactions and the associated bore hole problems (Amanullah et al., 2011). In addition, due to large surface area per volume, it is expected that less proportion of nanoparticles need to be employed relative to micron-sized additives conventionally used to achieve a similar effect. As nano based fluids require small volumes, it significantly decreases drilling time and increases the productivity index of the drilling activity by increasing the rate of penetration (ROP). The main application of nanoparticles would be to control the spurt and fluid loss into the formation and hence control formation damage (Husein et al.,2012a; Amanullah et al., 2011). The nanoparticles can form a thin and impermeable mud-cake. Due to its high surface to volume ratio the particles in the mud cake matrix can easily be removed by traditional cleaning systems during completion stages. Thus, the nanoparticles can be used as rheology modifiers, fluid loss additives and shale inhibitors at very small concentrations (Zakaria et al., 2012; Amanullah et al., 2011; Amanullah and Al-abdullatif, 2010). Research showed that the thermal conductivity and the convection heat transfer coefficient of the fluid can be largely enhanced by the suspended nanoparticles (Xuan et al., 2003; Choi et al., 2001). These features make the nanofluid very attractive in cooling or lubricating application in many industries including manufacturing, transportation, energy and electronics, etc. Hence, the enhanced thermal conductivity of drilling fluid will provide efficient cooling of drill bit leading to an increase in operating life cycle of a drill bit. Micro and macro sized particles used in drilling fluid accelerate the wear and tear of the surface and subsurface equipment. Conversely nanoparticles due to its extreme tiny size, the wear and tear of down hole equipment due to abrasive action is negligible because less kinetic energy 22

39 impacts by nanoparticles. It is explained by the role of kinetic energy or dynamic action (sedimentation speed) of nanoparticles on the bit. Particles in suspension in liquid medium are subjected to three kinds of forces: a) gravitational forces the particles to fall down, b) viscosity of the liquid decreases the speed of their displacement and c) Archimedes force is opposed to gravitation forces in this case. By applying fundamental relation of dynamics, the expression of the steady sedimentation speed of a particle is can be approximated by Stokes law: V t = ( ) (E 2.1) From the equation E 2.1, it is noticed that the speed varies in proportion to the square of the radius of the particle. Particles with larger radius will sediment much faster than smaller ones. Hence, comparing with the larger sized particles (micro or macro additives) nanosized particles, the kinetic energy will be much less due to its low sedimentation speed. Therefore Amanullah et al.(2011) reported that nanoparticles could not harm the downhole tools during the dynamic operation. Nanoparticles could improve the electrical conductivity of drilling fluids by forming electrically conductive filter cake that highly improves real time high resolution logs (Monteiro and Quintero,2012). Due to low requirement of nano additive in mud formulation, nanobased fluid could be the fluid of choice in conducting the drilling operation in sensitive environments. The wettability of a formation can be changed by nanoparticles. The use of nanoparticles to change rock wettability and its subsequent effect on oil recovery has been reported by several authors (Qinfeng et al., 2010; Ju et al., 2006). From experimental results, it is expected that some nanoparticles application in EOR will maximize recovery and boost hydrocarbon production. In a parallel research to this one, Nwaoji et al.(2013) and Nwaoji (2012) found nanoparticles with LCM blend bridge the formation, act as an excellent propping and sealing properties of the fracturing fluid and increased the core fracture breakdown pressure (fbp) resulting in strengthening wellbores in shale formations. 23

40 2.6.1 Nanoparticle synthesis Selection of nanoparticles is dependent on its properties and particle size. There are different methods for nanoparticles synthesis which are categorized as dry and wet methods. Dry methods consist of jet and ball milling, micronizer whereas wet synthesis consist of solvent evaporation, chemical precipitation, spray drying and emulsion method (Midoux et al., 1999). Husein and Nassar (2008) reported five main techniques for preparation of nanoparticles; namely: (i) chemical co-precipitation, (ii) electrochemical, (iii) sonochemical, (iv) sol-gel processing and (v) microemulsions. Engineered nanoparticles are designed and manufactured with specific properties or compositions (e.g., shape, size, surface properties, and chemistry). All these techniques require the presence of a stabilizing agent to prevent aggregation of the resultant nanoparticles. Among them, water-in-oil, (w/o), microemulsions serve as an excellent media for the preparation of wide variety of colloidal nanoparticles. (w/o) Microemulsions typically provide easy control over nanoparticles size and shape and produce highly homogeneous nanoparticles due to their ability to mix reactants efficiently at the molecular level (Husein and Nassar, 2008). Nanoparticles get stabilized in (w/o) microemulsions by means of steric stabilization which is provided by the adsorbed surfactant molecules on the surface of the nanoparticles (Nassar and Husein, 2007a; 2007b). The surrounding surfactant layer limits their growth and protects them from aggregation, and hence, maintains their colloidal stability. Stability of colloidal particles is dictated by the net between the repulsive and the attractive forces which emerge as the particles approach one another due to Brownian motion and/or other external forces. When repulsive forces dominate, stable colloidal suspension is maintained, while net attractive forces lead to particle aggregation and precipitation. Van der Waals force is an attractive type interaction and is inversely proportional to the sixth power of the distance between the surfaces of the particles (Husein and Nassar, 2008; Nassar and Husein 2007a,b; Kostansek, 2003). (w/o) Microemulsions are thermodynamically stable systems and are different in nature than the kinetically stable invert emulsions typically used in drilling operations. Entropy of dispersion is very important parameter for the formation of microemulsion systems. Entropy of dispersion 24

41 contributes to very effective mixing of water pools and, hence very high rate of intermicellar exchange dynamics compared to invert emulsion systems. This high rate is indispensable for formation of nanoparticles in (w/o) microemulsions (Husein and Nassar, 2008). In-situ formation of nanoparticles in invert emulsions, on the other hand, relies heavily on effective mixing and shearing. This research attempted to adopt (w/o) microemulsion technique to prepare nanoparticles in invert emulsion drilling fluids with this fact in mind. Figure 2.10 shows the NPs preparation in an invert emulsion drilling fluid following chemical co-precipitation method. By adding small quantities of nanoparticles, or preparing them in-situ, in drilling fluid ensuring mixing at the molecular level, wrapping and interpenetrating network achieve this new class fluid that could be used in down hole drilling. The nanoparticles will be tightly held in the water pools, surrounded by surfactant layers that limit their growth and protect them from aggregation. A number of investigations were performed using nanoparticles in drilling fluid to improve the functional characteristics described earlier (Cai et al.,2012; Monteiro and Quintero,2012; Tour et al.,2011; Manea, 2011; Srivatsa, 2010; Abdo and Haneef, 2010; Chenevert and Sharma, 2009; Sensoy, 2009; Agarwal et al., 2009; Roddy et al.,2009; Paiaman and Al-Anazi,2008; Sayyadnezad et al.,2008; Jimenez et al.,2003), but none, had in fact adopted in-situ preparation technique, and most used commercial nanoparticles. Figure 2.10: Schematic representation of NPs in invert emulsion fluid. 25

42 2.7 Nanoparticle-based drilling fluids The spurt loss is considered one of the sources of solid particles and particulate invasion into the formation. Beeson and Wright (1952) observed that spurt losses ranging from 2.3 to 7 ml may take place in the formation having permeability in the range of 7 to 469 md. Muds producing soft and thick cakes increase the potential of differential sticking and formation damage. This highlights the importance of mud design to produce clear filtrate with virtually no spurt, low filtrate volume and well-dispersed and tightly packed thin mud cake. It is often impossible to fulfill certain functional tasks using conventional macro and micro type mud additives. According to Amanullah and Al- Tahini (2009), due to the scope of manufacturing of tailored made nanoparticles with custom made functional behavior, ionic nature, physical shape and sizes and charge density/volume opened the door to the development of a new generation fluid for drilling which is expected to play a leading role in overcoming technical challenges associated with the conventional macro and micro particles based drilling fluid. In order to increase the penetration rate in deep drilling systems and prevent fluid loss researchers are working on developing a new nano-particle-based drilling fluid and additives that can improve the efficiency, extend the life of drilling fluids, control fluid loss and less susceptible to degradation under high temperature and pressure (HTHP) operations. Recent experiments have demonstrated that nano fluids have attractive properties for applications in heat transfer, drag reduction, binding ability for sand consolidation, gel formation, wettability alteration, and corrosive control (Mokhatab, 2006; Krishnamoorti, 2006). Amanullah et al. (2011) disclosed a WBM with less than 1 wt% NPs, resulting in no mud spurt loss. High potential for reducing differential pressure sticking problems while drilling, reduce torque and drag problems in deviated, horizontal extended reach and multi-lateral drilling operations. Tiny concentration of less than 1% w/w of nanomaterial plays an important role in increasing rate of penetration. But more interestingly, Amanullah et al. (2011) formulated their nano-based drilling fluids by mixing nanoparticles with the base fluid, i.e. water. They did not use a real drilling fluid 26

43 formulated by industry. Therefore, they were in need for very active stabilizers to maintain the nanoparticles dispersed. The polymeric viscosifier and surfactant additives used are costly, i.e. not practical. Moreover, industrial drilling fluids contain many additives that may compromise the stability of their drilling fluids and render them ineffective. For all practical purposes their drilling fluids are model drilling fluids which have no industrial applications. Also, looking at the fluid loss experimental results, it is clear that fluid loss reduction for a period of 30 min was not improved at all or became negative compared to the bentonite based mud (without nanoparticles as a control sample). Calcium carbonate is a well-known weighting material in drilling fluid. Reducing solid, i.e. clay, content by introducing CaCO 3 is not a new idea. Their claim regarding increasing ROP, decreasing formation damage and decreasing the coefficient of friction are indirectly related to NPs addition. They only improved the rheological behavior of fluid in terms of stability and gel strength. Srivatsa and Ziaja (2012) disclosed a WBM with viscoelastic surfactant and 10 wt % NPs. It also tests higher amounts of 20 wt% and 30 wt% NPs. 10 wt% is considered as the minimum concentration needed for fluid loss and address differential sticking problems. The authors used model drilling fluids formulated by adding different proportions of surfactants, polymers and/or nanoparticles. No actual nano-based drilling mud was used. A large amount of surfactant and polymers were used in fluid formulation. With the addition of NPs at different concentration resulted at % fluid loss reduction. Due to the large amount of NPs with surfactant-polymer blend could make the drilling fluid practically undesirable in terms of drilling cost and other functional activities. Water based mud in real application do not mix with large amount of surfactant and polymers. Polymer-surfactant blend suppress the NPs fluid mud cake with a desirable thickness so that differential sticking problem can be eliminated. No experimental results and mechanism proved the lubricity nature of their commercial silica NPs used in their works. Aston et al. (2002) disclosed NPs at a concentration of 0.7 to 1.4 wt% and discussed preventing differential sticking and formation damage avoidance as well as fluid loss reduction. Three components were required for fluid loss control emulsified brine, fine solids, and fluid loss control chemical such as Gilsonite, asphalt or synthetic polymer. High 27

44 concentrations of fluid loss additives were not required since they did not improve fluid loss control. The study focused on the effect of every component of an OBM on fluid loss, and in fact formulated the fluids using the base oil and added one component at a time. Once the solid particles were tested, they were not in suspension, Illite provided loss prevention but it was in the micro-domain. The use of engineered nanoparticles increases the intra-granular strength and reduces permeability and porosity of formation. Oil-based muds offer a good solution to shale instability problems. Nevertheless, development of water-based mud is also needed for environmentally sensitive areas where nanoparticles might be effective in plugging pore throat openings and stabilizing the wellbore. Sensoy (2009) disclosed a WBM with nanoparticles. It states that 5 wt% NPs is not as effective as 10 wt% which is considered the minimum needed for fluid loss. Reduced fluid penetration into Atoka shale up to 98% compared to sea water. NPs were between 5 to 20 nm in size. No actual nano-based drilling fluids were used. The author used dispersion of nanoparticles in water. Permeability reduction was taken longer time with higher amount of silica NPs. Extra additives were required to disperse the silica NPs in drilling fluid. Tests were not covered for invert emulsion mud and HTHP conditions. The application of this fluid pertains to nanopore throat reduction rather than considering the overall fluid loss. We anticipate that this approach could damage the formation by forming internal plugging into the formation and in this manner could significantly increase wellbore instability problems. As it took longer time to reduce permeability means the penetration of drilling fluid particles or NPs passes from the hole into the formation. Therefore we can conclude that spurt loss is higher in this case before pore plugging occurred. Similarly Chenevert and Sharma (2009) investigated permeability reduction of shale formations using specific nanoparticles in the water based drilling fluids. By identifying the pore throat radii of shale samples, the investigators were able to select fine particles that would fit into the pore throats during the drilling process and create a non-permeable shale surface. They formulated their water based mud with silica, iron, aluminum, titanium or other metal oxides and hydroxides nanoparticles having size range of

45 nm and also composed of a surface active agent (alkyl amines, alkyl sulphates, alkyl sulphates containing aromatic rings, Polyethylene glycol (PEG), Polypropylene glycol (PPG) etc). The minimum concentration required to reduce the fluid penetration was 10 wt% NPs. It was observed that addition of 10 wt% of silica NPs reduced fluid penetration by 72% in 36 h for Atoka Shale and 50% in 23 h for GOM Shale. It was also observed that high concentration of nanoparticles (41 wt%) completely plugged the pore throats by 2 h for Atoka Shale. Thus, these fluids based on nano fluids can be used effectively in horizontal and directional shale drilling as nanoparticles can easily penetrate into the shale and hence drastically reduce the shale-drilling mud interactions and stabilize the wellbore. It was also found by Huang and Crews (2008) that nanocrystals with hydraulic fracture proppant reduced fines migration without disturbing productivity. The NPs asscociate with VES (viscoelastic surfactant) micelles through surface adsorption and surface-charge attraction to stabilize fluid viscosity at high temperatures and produced a pseudofilter cake of viscous VES fluid on porous media that reduced the rate of fluid loss significantly and improved fluid efficiency for hydraulic fracturing. Ying,(2012) disclosed the use of precipitated sub-micron barite as a weighting agent in drilling fluid. The precipitated barite showed less sag than conventional weighting agents which led to a decrease in pipe sticking. The precipitated barite was used in amounts from % by volume and did not lead to an unwanted increase in viscosity. They also reported the use of polymers, which might bridge the particles and produce thin mud cake as per literature. Thin mud cake leads to a decrease in pipe sticking. So, no clear distinction between the roles of the submicron particles or the polymer in reducing pipe sticking problems was made in Ying,(2012) work. Ballard and Massam (2012) investigated precipitated submicron barite as a weighting agent in a drilling fluid. The precipitated weighting agents showed less sag than conventional weighting agents. Preferred precipitated agents are calcium carbonate, barium sulfate, iron oxide, magnesium carbonate and a wide variety of others. The precipitated weighting agents have a particles sizes varying between 20 and 90 nm. They also 29

46 disclosed that precipitated barium sulfate can be made by mixing barium chloride and sodium sulfate. Their works mainly focused on optimizing the viscosity of a drilling fluid and avoiding high viscosities while achieving high densities, an attribute especially needed for high pressure drilling. Further, unlike the methods developed in this study, the precipitated weighting agent is prepared ex-situ, where a coating material (dispersant) surrounds it, and is then added as a solid powder to the drilling fluid. Paiaman and Al-Anazi (2008) suggested to reduce the thickness of mud cake utilizing carbon black nanoparticles in drilling fluid. Carbon black NPs having specific Gravity= , initial diameter about 30 nm which after aggregation increased to nm was used in the works. The presence of carbon black particles reduced the thickness of the mud cakes and increased the thermal stability up to 3000 F (1649 C). Results have shown that adding 2 % by volume of carbon black to water based drilling mud decreased mud cake thickness, mud viscosity and yield point which led to less permeability and stuck pipe problems. Results also showed that thickness reduction was found better at high temperature and pressure. Griffo and Keshavan (2007) disclosed a drilling bit grease that comprises from wt% at least one nanomaterial. The grease is comprised of a common base stock such as synthetic oil, petroleum oil, and mineral oil or a combination thereof. Soaps, urea, fine silica, fine clays and silica gel may be used as thickeners. Preferred lubricating nanoparticles include molybdenum disulfide, graphite, carbon black, lead oxide, zinc nanoparticles ranges from nm. In their works it was found that addition of thickeners were necessary along with NPs. Although the invention did not claim that lubricity was based on NPs only; most of the metals considered in their works were heavy metals, which have a big environmental impact (e.g. lead). Uses of nanoparticles in drilling fluid will also expand its area of application in fracturing fluid additive, cement slurry additives, completion fluid additive. Nanoparticles increase the mechanical strength of the fluid. Roddy et al. (2009) observed that addition of nano-silica having a particle size in the range of about 1 nm to about 100 nm and present in an amount in 30

47 the range of about 1% to about 25% by weight to the cement slurry (comprised of cement, water) reduced the cement setting time and increased the mechanical strength of the resulting cement explains the fact that light nanomaterials can take overall load. Some nanoparticles may carry magnetic property which can change the density of fluid when necessary. Jimenez et al. (2003) made an effort to prepare nanoparticles treated drilling fluid which was responsive to the change density state required to control subsurface pressures, preserve and protect the drilled hole. The nanoparticles were sized between 0.5 and 200 nm and formed into clusters having average size of between 0.1 µm and 500 µm. The clusters were formed by incorporating the nanoparticles into a matrix of glass or ceramic. Group VIII metals Cd, Au and their alloys were found to provide an excellent result in adjusting fluid density in a reversible manner. They have shown that 90% of the supermagnetic nanoparticles from the treated drilling fluid from the downhole location again recovered to a magnetic field at the surface resulting in the adjustment of drilling fluid density within a short period of time and circulated the magnetic nanoparticles to the surface level for reusing them in the drilling fluid. From the study it is shown that viscosity could also change with the addition of nanoparticles. Javora and Qu (2009) used an aqueous based well treatment fluid containing an additive having a median particle size of the calcium carbonate nanoparticles less than or equal to 1 µm as viscosifying additive. The amount of calcium carbonate nanoparticles used in drilling fluid was approximately 20 wt%. The nanoparticles used in well treatment fluid were capable of being suspended in the fluid without the aid of a polymeric viscosifying agent. Nanoparticles suspended in a well treatment fluid even at high temperature, e.g. 350 F, typically exhibit sag no greater than about 8%. It was observed from the study that addition of nanoparticles altered the viscosity of the fluid. Using nanoparticles, Huang and Crews (2008) reduced the leak off viscoelastic surfactant simulation fluids at high temperature for completion applications. They also discovered that, micellar fluids such as surfactants can have wall building characteristics when small concentrations of nanoparticles are added. The nanoparticles pseudo-crosslink the elongated micelles in a manner similar to crosslinking Polymers. They further investigated the pseudo-crosslink characteristics of the 31

48 worm like micelles in surfactant systems and concluded that nanoparticles first associate with end caps which are energetically unfavorable and then this becomes junctions for worm like micelles, which enhance the wall building characteristics of the fluid system, improve thermal stability and also improve the viscosity of the fluids. Berret (2004) investigated the interaction of nanoparticles with co-polymers and observed the formation of super-micellar aggregates. Nanoparticles which have a hydroxyl group (-OH) on the surface and causes nanoparticles to be agglomerated. This agglomeration causes poor dispersions and addition of surfactants reduces this problem. Asphaltic materials are also used as additive to bind the metal oxides at high temperature tend to decrease the fluid loss. McGlothlin and Baggett (1972) invented an invert emulsion drilling fluid employing manganese oxide with asphalt constituents. Addition of MnO 2 the fluid loss reduction was approximately 66 % than the control sample at 300 F with substantially no breakdown of the emulsion. The amount of metal oxide or oxides employed were from about 1 to about 10 wt%. Miller (1971) improved plastering properties and reduced fluid loss properties at extreme conditions of borehole temperature and pressure using asphalt material as a filler or plaster at high temperature. He formulated the oil based drilling fluid containing a small amount of a secondary weighting material inert to the fluid and having particle size of no more than 3 µm. Suitable inert materials for the secondary weight phase were the iron oxides and titanium oxides. Each sample was tested for fluid loss by maintaining the fluid in a hightemperature, high pressure filter press at 300 F and 500 psi for 30 min. The investigations showed that iron oxides having size 3 μm had 12 % less fluid loss, TiO 2 particles having 0.18 μm had 36 % and 0.19 μm showed 12 % less fluid loss than the control samples. The investigation again showed that addition of TiO 2 with fine barium sulphate lower the fluid loss 38% than the control samples. Ravi et al. (2011) made an effort to introduce a lost circulation composition into a lost circulation zone to reduce the loss of fluid into the formation. The lost circulation composition comprised of portland cement in an amount of about 10% to about 20 % by weight of the lost circulation composition, nano-silica in an amount of about 0.5 % to about 4 % by weight of the lost circulation composition, the nano-silica having a particle size of about 1 nm to about

49 nm, amorphous silica in an amount of about 5 % to about 10 % by weight of the lost circulation composition, synthetic clay in an amount of about 0.5 % to about 2 % by weight of the lost circulation composition, sub-micron sized calcium carbonate in an amount of about 15 % to about 50 % by weight of the hydraulic cement and water in an amount of about 60 % to about 75 % by weight of the lost circulation composition. It was investigated that lost circulation compositions rapidly developed static gel strength and remained pumpable for at least about 1 day. The sample was observed to gel while static but returned to liquid upon application of shear. Thus mixed nanocomponents with cement could reduce the setting time for mud cake formation and development of gel strength. The retention of nanoparticles from concentrated dispersions in sedimentary rocks has recently been investigated by Rodriguez et al. (2009). They mentioned that NPs retention by the porous medium had consistent competition between adsorption (vander Waals attraction between nanoparticles and solid surface) and desorption (Brownian motion and hydrodynamic drag). Tour et al. (2011) used drilling fluid including chemically converted nanoplatelet graphenes with functional groups. The graphene comprised about 0.001% to about 10 vol.%. The functionalized chemically-converted graphene sheets were about 1.8 nm to about 2.2 nm in thickness. Whatman 50 allowed some graphene oxide to pass through the filter. Filtration rates varied from 0.10 ml/min to 0.28 ml/min for graphene oxide and chemically converted graphene solution on whatman 50 filter paper. Surface charge plays an important role on the transport of nanoparticles and trapped in porous media. Poulton and Raisweel (2005) reported that the natural spherical iron oxides nanoparticles (10-20 nm) in sediments tend to aggregate at the edges of clay grains due to their surface charge characteristics. Kosynkin et al. (2012) showed that using graphene oxide (GO) with a concentration of 0.2 % (w/w) by carbon content exhibited % fluid loss reduction in water based drilling fluid compare to the water based control drilling fluid sample. GO preparation technique was not user friendly. During spurt loss, NPs pass through the filter cake which could damage the formation due to internal pore blockage by their NPs. Saboori et al. (2012) also investigated mud cake thickness and water loss using CMC nanoparticles having particle size distribution 27 nm to 930 nm with average size of 47 33

50 nm in water based mud. NPs were prepared by ball milling method. It was found that existance of naoparticles caused the amounts of water loss and mud cake thickness to decrease. Compare with the micron-sized CMC (10 gm) used in control samples, nano CMC (10 gm) can decrease only 7 % fluid loss. Manea (2011) investigated nanoscale polymer additives in water based mud to measure the fluid loss. 2.5 wt% nano Xanthan gum and 3 wt% nanopolymer together in mud reduced 29 % water loss whereas mud treated with NaOH and addition of 2.5 wt% nano Xanthan gum and 3 wt% nanopolymer together reduced fluid loss by 48% led to the conclusion that in an alkali medium, the efficiency of Xanthan gum was enhanced. On the other hand, increasing the sodium hydoxide concentration in the mud also increase the ph of the mud which could lead to the undesirable mud viscosity reported by Irawan et al. (2010). Deep water drilling has been emerging as an important drilling activity to all oil and gas companies in order to increase the daily production of crude oil. Drilling in deep water wells normally associated with high temperature high pressure (HTHP) condition. HTHP wells are generally considered to be those which encounter bottom hole temperatures in excess of 350 F (177 C) and more than 500 Psi pressure. A research program initiated by Tran et al. (2007) to develop nano particles based drilling fluids to perform in high temperature drilling. Under their study, they assumed the benefits of using dragreducing polymer additives with nanoparticles could improve the drilling penetration rate, lubrication, and cooling the drill bit. Hydrogen sulphide which is corrosive, toxic and dangerous gas largely produced in gas and petroleum industries. It can diffuse into the drilling fluid from formations during oil and gas wells drilling. Investigations are being carried out to remove hydrogen sulphide from this drilling fluid to reduce the environmental pollution, protect the health of drilling personnel and prevent corrosion of pipelines and equipments. Sayyadnejad et al. (2008) showed that utilizing zinc oxide (ZnO) nanoparticles synthesized by spray pyrolysis method in water based drilling mud removed hydrogen sulphide completely within 15 min where as bulk zinc oxide removed 2.5% of hydrogen sulphide in as long as 90 min under the same operating conditions. The results obtained in this research 34

51 showed that ZnO nanoparticles in the range about nm size, m 2 /g specific surface area used as an effective scavenger for removing hydrogen sulphide (H 2 S) from drilling mud. Since HTHP/environmentally sensitive/remote areas drilling are inherently expensive, the choice of drilling fluids and its continuous phase require careful evaluation to successfully handle the environmental challenges. Drilling fluids formulated with low aromatic oil (contain less than 1% of aromatic fractions) are 5 to 14 times less toxic than diesel based fluid under the EPA criteria. LC 50 currently has a limit of 30,000 ppm for the suspended particulate phase of the whole mud (Sáchez et al., 1999). Research concerning the toxicity of NPs is still in its infant stages. However a study was investigated by García et al. (2011) showed that iron oxide NPs exhibit low or no toxicity at low concentration (0.67 mg/ml) and reported LC 50 = 2.3 x 10-4 mg/ml which would be special interest to use it in drilling fluid. The cost of nanobased drilling fluid may make them economically feasible. Srivatsa (2010) reported the cost of a typical oil based drilling fluid containing silica NPs was costly. A comparative cost between commercial silica NPs used by Srivatsa (2010) and NPs prepared in ex-situ/in-situ method by Husein et al. (2012) shown in the following table: Table 2.1: Comparative cost analysis study of NP-based drilling mud (Srivatsa, 2010). Component Volume Cost/unit ($) Cost/component ($) Diesel Oil 0.8 bbl Emulsifier 6 lbs Water 0.14 bbl NA NA Gel 5 lbs Calcium Chloride 20 lbs Lime 3 lbs Total Cost (1bbl) 52.9 NP (silica) at 10 wt% conc. Srivatsa (2010) 35 lbs In-situ/ex-situ NPs 1 wt% Fe(OH) 3 conc. prepared by Husein et al. (2012a) 4.8 lbs NA

52 From the above table, total cost of the 1bbl diesel based mud is $ Addition of commercial NPs (10 wt%) contributed to $140.4/bbl, whereas in-situ/ex-situ NPs based mud overall cost would be $65.71/bbl. So based on the literature in-situ/ex-situ NPs costs are less expensive and more cost effective in terms of drilling cost per well. In respect to filtration control of drilling fluid suggests that there should be a proper criterion of particle size distribution. Experimental works presented by different researchers in literature showed the single size of NPs used in mud formulation and reached hardly near to the objectives. Whereas we suggest the cost effective in house ex-situ and in-situ prepared NPs having wide range of particle size distribution could be successful to handle the different permeabilities and porosities of the formation. Nonetheless we can conclude that the addition of NPs to drilling fluid has a positive effect on fluid properties. In this work we evaluate fluid loss performance along with other characteristics of drilling fluid after blend of custom prepared engineered NPs in drilling fluid. From earlier literature review a wide range of NPs are preferably selected from metal hydroxides, e.g. iron hydroxide, metal carbonates, e.g. calcium carbonate and metal sulfate and sulfide e.g barium sulphate and ferrous sulfide respectively. 2.8 General characteristics of drilling fluid filtration The invasion of filtrate occurs once filtration starts during drilling. It is well known that there is a mud spurt at the start of a filtration process before filtration begins. In the drilling well, mud spurt may be much larger when filtration takes place against the more permeable rocks. In fact they can be infinite (i.e. circulation is lost) unless the mud contains particles of the size required to bridge the pores of the rock, and thus establish a base on which the filter cake can form. Only particles of a certain size relative to the pore size can bridge these pores. Particles lager than the pore openings cannot enter the pore, and are swept away by the mud stream. Particles considerably smaller than the opening, on the other hand, invade the formation unhindered. Intermediate particles of a certain critical size stick at bottle-necks in the flow channels, and form a bridge just inside the surface pores. Once a primary bridge is established, successively smaller particles, down to the fine colloids, are trapped, and thereafter only filtrate invades the 36

53 formation. The mud spurt period is very brief, a matter of a second or two. Krueger (1963) produced a typical curve for cumulative filtration volume versus time as shown in Figure Equilibrium conditions are reached after about 6 to 10 h and fluid loss rate becomes constant as indicated by the straight line portion of the curve. The first portion of the curve is the dynamic fluid loss rate through equilibrium dynamic mud cake laid down on newly exposed formation. The second portion of the curve represents the duration when circulation was stopped and the static mud cake allowed to build up on top of the dynamic cake. The third portion of the curve represents the period when the circulation is resumed and equilibrium dynamic fluid loss rate is established. During T 0 and T 1 time period, deposition of particles occurs and is characterized by filtration through a cake of constant thickness. Outmans (1963) suggested that during this period, the rates of particle deposition and cake compaction must be equal. During T 2 and T 3, filtration rate, cake thickness and permeability are constant. The next phase of the curve corresponds to the period of static filtration (T 3 to T 4 ) which occurs when circulation is stopped. During this time filter cake thickness will start to increase. This static filtrate affects the subsequent drilling operation. Therefore it is necessary to predict the static fluid loss in which the filter cake forms upon a previously deposited dynamic filter cake. It is logically thought that the lower the mud cake permeability, the thinner the mud cake and the lesser the volume of filtrate from muds. The primarily concern is to control the static filtration rate/loss in order to overcome drilling and completion difficulties associated with filter cake growth to great thickness during long period of static filtration, which is often the case during swabbing, fishing and trips. Thick filter cakes restrict the easy passage of downhole tools and allow excessive amount of filtrate to move into the formation, creating a potential cause of caving and a long term formation damage problem as a result of fluid invasion (Maduka, 2009). In the third phase (T 4 to T 6 ) of Figure 2.11, a new dynamic equilibrium filtration rate is achieved and total resistance to filtration increases due to cake depositing in the static phase. This theory was proposed by Ferguson and Klotz (1954) and also confirmed by Peng (1990). 37

54 Figure 2.11: A characteristic filtration plot of drilling fluid during drilling (Krueger, 1963). Darley (1965) reported that initial filtration rates depended on the concentration of solids and particle size distribution in the mud. It was suggested that there was a critical size range for bridging in the surface pores. Once the pores are bridged by appropriate size particles, successively smaller ones are trapped, and a filter cake is established. Schremp and Johnson (1952) described the drilling mud filtration process into two steps: (1) bridging of openings in the filter medium, and (2) filtration of fluid throughout the filter cake that developed on the filter medium as the filtration continues. Gates and Bowie (1942) discussed the relationship between particles size distribution and filtration properties. They showed that the best filtration control properties of the muds were composed of approximately 65 wt% colloids, 30 wt% silt and 5 wt% sand, whereas the poorest filtration control muds were composed of 1 wt% colloids, 94 wt% silt and 5 wt% sand. And increasing temperature increased the filtration rates of the fluids tested. Barkman and Davidson (1972) showed three characteristic shapes of the filtration curve as shown in Figure

55 Figure 2.12: Three Types of Filtration Curves (Barkman and Davidson, 1972). They concluded that the shape of the curves depended on the sizes of the suspended solids and filter medium. Figure 2.12a results when the suspended particles are larger than the pores of the filter medium and no invasion takes place. The intercept of the straight line at time zero becomes negative. Figure 2.12b occurs when the suspended solids are much smaller than the pores of the medium and invasion takes place at the early part of the experiment. Therefore a positive intercepts is apparent. In Figure 2.12c S-shaped curve, which is not common, occurs when several filtration mechanisms (plugging mechanisms, pore throat blockage and pore filling) operate simultaneously. It is evident that filtration curves mostly depend on the particle/pore-throat size ratio, filtration velocity and mechanism of capture of particles (Pang and Sharma,1997). Jones and Babson (1935) investigated the filtration properties in artificial formation prepared from the unconsolidated sand at pressures upto 4000 psi and temperatures upto 275 F under dynamic conditions. They found that filtration flow rates attained a constant value at the end of about 2 h. Regardless of the nature of mud or temperature, 39

56 variation in pressures above 500 psi had very little effect on the filtrate flow rate or on the mud cake thickness. It was found that the fluid loss increased rapidly with reduced apparent viscosity for weak thixotropic mud but unaffected for strong or moderately strong thixotropic muds. Byck (1940) investigated the effect of formation permeability on the filtration characteristics of drilling fluids. It was shown that the filtration rate was dependent on the permeability of the cake as long as it was several orders of magnitude lower than the permeability of the formation. Willams and Cannon (1938) performed static filtration tests at pressures ranging from psi for a wide range of drilling fluid and concluded that cake resistance increased by the addition of bentonite and rate of filtration could be varied by adding weighting materials. Larsen (1938) reported the following relationships drilling fluid filtration experiments at pressures ranging from psi and temperatures in the range of F. Fluid loss α t 1/2 (E 2.2) Fluid loss α (E 2.3) Fluid loss α Cake thickness (E 2.4) It was also found that fluid loss increased by calcium ion flocculation of the mud. Flocculation of muds causes the particles to associate in the form of a loose, open network causing considerable increase in permeability. Conversely, deflocculation of a mud by the addition of a thinning agent causes a decrease in cake permeability. Moreover, most thinners are sodium salts, and at high concentration, the sodium ion may displace the polyvalent cations in the base exchange positions on the clay, thereby dispersing the clay aggregates, and further reducing cake permeability. Thus, the electrochemical conditions prevailing in a mud are a major factor in determining the permeability of its filter cake (Maduka, 2010). Fordham et al. (1988) proposed two fundamental models for dynamic filtration of a drilling fluid. One of them is convection diffusion balance model based on the fluid loss control between the convective transport of mud particles towards the filtration surface 40

57 by the filtration flux and the diffusion of particles away from the surface. Another one is particle adhesion model which suggests that particle permanently stick at the cake surface depends on both the filtration rate and the colloidal interactions between particles. Once stuck, particles are unable to migrate away from the surface. Milligan and Weintritt (1961) reported the effects of elevated temperature on filtration of drilling fluids. They concluded that at an elevated temperature, muds might undergo irreversible reactions or changes in composition. The increase in temperature reduces the viscosity of the filtrate, and therefore, cumulative filtrate volume increases proportionally. Many organic filtration control agents start to degrade significantly at temperatures above 100 C. Chemical degradation of one or more components used in mud can affect filtrate properties. Electrochemical equilibria which govern the degree of flocculation and aggregation, altering the permeability of the filter cake due to an elevated temperature (Maduka, 2010). The static filtration equation for mud filtrate through a mud cake is described by Darcy s law. In 1856, Henry Darcy published the following equation to describe the flow of fluid through porous medium (Chelton, 1967): dq dt f ka P h (E 2.5) mc Larsen (1938) found that if a mud was filtered through paper at constant temperature and pressure, fluid loss Q f was proportional to square root of time t. Although this finding is not strictly true for all muds, but close enough for practical purposes. Carman (1938) extensively studied the cake filtration and concluded that Darcy s law is applicable for mud filtration. It is shown that drilling fluid loss behavior with time has been estimated from the experimentally derived data by using Darcy law in the literature (Maduka, 2010; Kumar, 2010; Hoff et al., 2005). 41

58 In current study, API static filtration equation is described at Chapter 5 as a part of sequential filtration for realistic drilling condition for predicting the drilling fluid loss control by nanoparticles. 2.9 Filtration mechanism Particles in suspension in a liquid medium are subjected to three kinds of forces: a) gravitation forces, b) drag forces and c) Archimedes force (Martin and Ohmae, 2008). Filtration occurs when fluid-containing particles are captured flowing through a porous medium. Particles are deposited due to the different mechanisms as described by Zamani (2010); Farajzadeh (2004) and dezwart (2007). Particles transport by interception. This particle transport mechanism becomes important when particles are larger in size. Interception occurs when particles following a streamline hits the surface of a grain and attach to it. Particles having equal density of the fluid follow the streamline in porous media at low velocities. When the particle is retained by a previously deposited particle, it is referred to as bridging. Figure 2.13 shows the bridging of the particles in a pore throat with varying particles diameter. It shows the bridging effect that occurs when two or more particles arrive at the same moment to pass through or when one particle is already attached to the grain and another particle wants to pass through. Figure 2.13: Bridging effects with varying particles diameter in pore throat (de Zwart (2007), Farajzadeh (2004)). 42

59 Happel (1958) used the following relationship to calculate the probability of collision. = (E2.6) A s is the porosity dependent parameter and express as = (E2.7) where, z= 2-3p+3p 5-2p 6 and p = (1-φ) 1/3 ; where φ is the porosity of medium. Particles transport by Impaction. When the density of particle is larger than that of the fluid, inertia deviate the approaching particles from the stream line and attach them to the surface of a grain. This mechanism is responsible for collecting larger particles. The inertial effect is characterized by the dimensionless Stokes number (Tien,1989 ; Ives, 1970) as N st = (E 2.8) Particles transport by Sedimentation. When the density of particles is different than the density of the fluid, the fluid velocity will be different than the particles velocity. The expression of steady state sedimentation velocity of particles in dilute suspension, V t are given in E 2.1. Particles with large radius will sediment much faster than the small ones and less kinetic energy will be impacted by small particles. Particles transport by Diffusion. Small particles experience to random Brownian motion that increases the collision frequency between particles and grains. The collision probability due to diffusion is equal to = 0.9 ( ) (E2.9) 43

60 Diffusion is important for small particles (dp<1 μm) and is usually neglected for larger particles. Ives (1970) found that the Brownian motion is dominant in transporting the submicron size particles but for the particles with greater than 1 μm in diameter, the viscous drag of the fluid restricts this movement and the mean free path of the particle is at most one of two particle diameter and therefore the mechanism is neglected. At a short distance, below 50 nm, two particles attract themselves due to van der Waals forces and it is expressed by the following relation: E vdw = - (E2.10) Van der Waals forces become more significant when h is below 10 nm. It is often used to describe the intermolecular interactions. For a better stability of a suspension, the Brownian motion is certainly most interesting. For mass transfer of nanoparticles in the presence of surface interaction forces over the filter grain d g, the Brownian diffusion coefficient can be defined by the Stoke-Einstein equation: (E2.11) P e = (E2.12) where Pe is the Peclet number (ratio of the convective motion of fluid to the movement due to Brownian diffusion). Particles transport by straining. When fluid containing particles approaches a pore throat, particles which are too small to pass through, get stuck there. This phenomenon is called straining or size exclusion (Farajzadeh,2004). It is determined by the ratio of porous media (pore throat) diameter to the particle diameter. When this ratio is less than 10 (too small) cake will build up on the surface of the media (Farajzadeh, 2004). If the concentration of particles is too high, they can also make a surface cake. In such cases, 44

61 many particles may reach the pore opening at a time and cram in it by aching action (Zamani, 2010). Particles transport by Electrical forces. Oppositely charged particles are attracted to a charged fiber as shown in Figure This collection mechanism is not limited to a certain particle size and electrostatic charges may influence particle deposition. van der Waals attraction forces and double layer repulsion forces are also significant for the capture and detachment of the particles. They determine whether a particle will stick to the grain or not. In other words, if the sum of the hydrodynamic and electrostatic forces is attractive, a particle will be retained and if the sum is repulsive particles will not adhere to the grain (Farajzadeh, 2004). All of the above mechanisms are summarized in Figure As NPs (d p << 1µm) are used in the current work, it is believed that diffusion is the most dominant mechanism as per Figure Electrostatic attraction - + Figure 2.14: Overview of Filtration mechanisms (adapted from Wilcox et al., 2010). 45

62 Figure 2.14: Effect of particle diameter on collision probability (Farajzadeh, 2004). Generally, three possible mechanisms may contribute to dispersed NPs deposition from invert emulsion drilling fluid. Brownian diffusion, steric stabilization, and van der Waals attraction forces. Double layer repulsion forces enhance particle stability in water based muds. a) NPs from the drilling fluid may physically plug or bridge across the flow paths in the porous formation upon the first filter cake is formed by clay particles. NPs plugging probability during drilling is shown in Figure The movement or transport of NPs by diffusion mechanism is believed to occur during fluid flow through porous medium. b) Chemical interaction between the fluid containing NPs and the formation rock and drilling fluid may precipitate NPs or other semisolids that plug the pore spaces. Adin et al. (1979) concluded that chemical interactions greatly affect the 46

63 attachment of particles on the surface. Raveendran (1993) found that water molecules strongly bind with certain clays and minerals by the strong hydrogenbonding surface groups such as hydrated ions or hydroxyl (-OH) groups. Van der waals attraction forces and electrical double layer repulsions can present in the NPs based system depending on whether the surfaces have respectively unlike and like potentials. c) NPs with surfactant act as pseudo-solid and due to hydrophilic and hydrophobic surface of surfactant effectively suspend NPs in the fluid system and create stable drilling fluid through steric stabilization which potentially improves the lost circulation. Figure 2.16: NPs plugging mechanism during drilling (courtesy of nfluids Inc, reprinted by permission). 47

64 Chapter Three: Experimental Methods This chapter describes the experimental procedures involved in the synthesis of the different nanoparticles (NPs), preparation of the NP-based drilling fluid, and the methods and instruments used to characterize the resultant NPs and the performance of the product fluid. The particles were characterized using TEM, SEM with EDX and ICP. The drilling fluid, on the other hand, was characterized using Fann mud balance for density and Fann viscometer for viscosity and the gel strength measurements. The NPbased drilling fluid lubricity was measured by Ofite lubricity tester and its filtration properties were evaluated using API low temperature low pressure (LTLP) and high temperature high pressure (HTHP) tests. Finally, the resultant mud cake was characterized using SEM and EDX images and its thickness was measured by digital caliper. 3.1 Drilling Fluid Samples The invert emulsion muds used in this study were supplied by several Calgary based drilling fluid companies, while the water-based mud was prepared in-house. Primarily, two mixes of the invert emulsion drilling fluids were tested; namely 90 oil:10 water (V/V) and 80 oil:20 water (V/V). The compositions of the invert emulsion and water-based muds are shown in Table 3.1. Table 3.1: Compositions of the invert emulsion and water based muds employed in this work. Invert Emulsion Mud Oil: water (V/V) =90:10 or 80:20 Base Oil= Low-aromatic oil Brine = 30% Calcium Chloride Organophillic Clays =15 kg/m 3 Primary Emulsifier= 10 L/m 3 Secondary Emulsifier = 5 L/m 3 Water based Mud Water= 500 ml Bentonite Clays= 10 g Surfactant = 0.5 g Xanthan= 1.5 g 48

65 The loss circulation material (LCM) content of the drilling fluid, mainly Gilsonite, was fixed at 1.6 wt% in the invert emulsion mud as recommended by one company. In some experiments, nonetheless, no LCM was added in order to provide a bench mark to evaluate NPs as sole loss prevention agents. The experiments mostly cover invert emulsion based mud characterization, although a number of filtration tests of water based mud were also performed. The in-house technique for the synthesis of the NPs developed in this work is a chemo-mechanical process. The unique process has enabled finely dispersed NPs formation in water-in-oil based drilling fluids as well as water-based drilling fluids. The severity of the drilling process, nevertheless, may induce particle agglomeration. However, the surfactants existing in a typical drilling fluid act as stabilizers and limit agglomeration through steric hindrance (Husein and Nassar, 2008). The method developed in this work is versatile and different types of precipitates of NPs were prepared; including Fe(OH) 3, CaCO 3, FeS and BaSO 4. Complete investigation was, nevertheless, focused on the performance of Fe(OH) 3 and CaCO 3 NPs. The method above uses two different approaches to prepare the NPs; namely in-situ and exsitu. The two terms essentially refer to whether the birth place of the NPs is inside or outside the drilling fluid. The NPs concentration was varied between 1 wt% and 5 wt% for both in-situ and ex-situ prepared particles. 3.2 NPs and NP-based drilling fluid formation The choice of Fe(OH) 3 NPs was based on the fact that the precursors are inexpensive, and the product NPs are good scavengers for H 2 S that may evolve during drilling (Husein et al., 2012a; Zakaria et al., 2012;Husein et al., 2010; Nassar et al., 2010). Hydrogen sulfide is a very toxic and corrosive gas and may easily diffuse into the drilling fluid from formation during drilling oil and gas wells (Sayyadnejad, 2008). Moreover, H 2 S may evolve during completion when acid wash is used to remove metal salts scale (Nasr-EI-Din et al., 2000). Similar to previous studies (Abdo and Haneef, 2010; Cai et al., 2012; Srivatsa, 2010; Sensoy, 2009; Manea, 2011; Agarwal et al., 2009; Jimenez et al., 2003; Paiaman and Al-Anazi, 2008; Roddy et al., 2009; Sayyadnejad et al., 2008), 49

66 and in order to establish the advantage of the in-house preparation method developed in this study, commercial NPs were employed at an early stage. Fe 2 O 3 NPs (Nano structured and amorphous materials Inc, Texas, USA) were used to provide bench marking. Fe 2 O 3 is a thermally degraded form of iron oxide hydroxide (Balek and Šubrt, 1995). On the other hand, CaCO 3 (fine/coarse) is a conventional lost circulation materials used as a bridging agent and/or weighting material in oil based as well as water based drilling fluids. The choice of nano CaCO 3 in drilling fluid was due to its wide range of applications in drilling fluid property manipulation from mud weight to fluid loss control. Apart from those nanomaterials, fluid loss studies were also carried using FeS and BaSO 4. There is a synergy between Fe(OH) 3 NPs and FeS NPs, as the latter is the final product of the reaction between Fe(OH) 3 NPs with H 2 S during drilling (Husein et al., 2010; Nassar et al., 2010). Moreover, both FeS and BaSO 4 (barite) are widely used as weighting materials in drilling fluids (Chilingarian and Vorabutr, 1983; Moore and Cannon,1936). They provide the high density needed to balance drilling operations Ex-situ preparation of NPs In the ex-situ method the NPs are formed literally out of place meaning the NPs formation reactions take place outside the drilling fluid. NPs are formed from their precursors in reaction vials at a standard condition. A general ex-situ NP-based fluid preparation sequence is shown in Figure 3.1. Aqueous precursor-1 Reaction & mixing at room temp (25 C and 200 rpm) Aqueous precursor-2 NPs Slurry Drilling Fluid NPs mixing with drilling fluid followed by high shear action ( min) Drilling fluid with desired NPs Figure 3.1: Schematic representation of the ex-situ method for NP-based drilling fluid preparation. 50

67 Fe(OH) 3 NPs Ferric hydroxide NPs were prepared by first solubilizing a specific amount of anhydrous iron (III) chloride powder (laboratory grade, Fisher Scientific Company, Toronto, ON, Canada) in 2 ml deionized water to give final concentration of 2.5 M followed by addition of a stoichiometric amount of NaOH (s) pellets (Fisher Scientific Company, Toronto, ON, Canada) under 200 rpm of mixing and 25 o C. The color of the aqueous solution turned reddish brown signaling the formation of precipitate of Fe(OH) 3(s) as per reaction (R1). FeCl 3(aq) + 3NaOH (aq) Fe(OH) 3(s) + 3NaCl (aq) (R1) Part of the particles was recovered for characterization and the rest was mixed with the invert emulsion drilling fluid in a slurry form. The fluids were mixed/sheared at 2500 rpm to unifromly disperse the slurry using Hamilton beach mixer. Similar to invert emulsion drilling fluid, ex-situ Fe(OH) 3 NPs were also prepared in the water based drilling fluid and tested only for LTLP fluid loss performance CaCO 3 NPs Calcium carbonate NPs were prepared by first solubilizing a specific amount of anhydrous sodium carbonate powder (99% ACS reagent, Sigma-Aldrich Fine Chemical, Toronto, ON, Canada) in 5 ml deionized water to give a final concentration of 2.26 M followed by addition of 1 ml of 7.6 M stoichiometric amount of aqueous calcium nitrate (99.5%, VWR, USA) under 200 rpm of mixing at 25 o C. The color of the aqueous solution turned white signaling the formation of precipitate of CaCO 3(s) as per reaction (R2). Part of the particles was recovered for characterization and the rest was mixed as a slurry with 500 ml invert emulsion drilling fluid. The fluids were mixed/sheared at 2500 rpm to unifromly disperse the slurry using Hamilton beach mixer. Ca(NO 3 ) 2(aq) + Na 2 CO 3(aq) CaCO 3 (s) + 2 NaNO 3 (aq) (R2) 51

68 Similar to invert emulsion drilling fluid, ex-situ CaCO 3 NPs were also prepared in the water based drilling fluid and tested only for LTLP fluid loss performance FeS NPs Iron (II) Sulfide NPs were prepared by solubilizing a specific amount of aqueous sodium sulfide (laboratory grade, Fisher Scientific Company, Toronto, ON, Canada) with aqueous iron (II) chloride (laboratory grade, Fisher Scientific Company, Toronto, ON, Canada). First, a specific amount of aqueous iron (II) chloride was solubilized in 1 ml deionized water to give a final concentration of 3.4 M followed by the addition of 4 ml of 0.9 M stoichiometric amount of aqueous sodium sulfide and mixing at 200 rpm and 25 o C. The color of the aqueous solution turned black signaling the formation of precipitate of FeS (s) as per reaction (R3). Finally, the product was mixed with the drilling fluid as a slurry using Hamilton beach mixer and sheared at 2500 rpm. Na 2 S (aq) + FeCl 2(aq) FeS (s) + 2 NaCl (aq) (R3) BaSO 4 NPs Ex-situ preparation of barium sulfate NPs followed the same procedure as above. A specific amount of aqueous barium chloride (Sigma-Aldrich, Toronto, ON, Canada) was reacted with aqueous sodium sulfate (VWR, Calgary, Canada) under 200 rpm of mixing at 25 o C. First, a specific amount of aqueous barium chloride was solubilized in 3 ml deionized water to give a final concentration of 1.14 M followed by the addition of 3 ml of 1.14 M stoichiometric amount of aqueous sodium sulfate. The color of the aqueous solution turned white signaling the formation of BaSO 4(s) as per reaction (R4). Finally, the product slurry was mixed with the drilling fluid using the Hamilton beach mixer and sheared at 2500 rpm to achieve a homogenous mixture. Na 2 SO 4(aq) + BaCl 2(aq) BaSO 4(s) + 2 NaCl (aq) (R4) 52

69 3.2.2 In-situ preparation The term in-situ NPs is used to mean that NPs were created in place. NPs were formed from their precursors by reactions in the drilling fluid. Formation of NPs in this manner minimizes particles aggregation and allowing easier handling than ex-situ prepared NPs. A general in-situ NP-based fluid preparation scheme is shown in Figure 3.2. The in-situ NPs preparation was used to prepare NP-based drilling fluid in invert emulsion as well as water based muds. Aqueous precursor -1 with drilling fluid Aqueous precursor -2 with drilling fluid Reaction, mixing and high shear action with drilling fluid at room temperature (25 C, 200 rpm and 2500 min) Drilling fluid with desired NPs Figure 3.2: Schematic representation of in-situ NP-based drilling fluid Fe(OH) 3 NPs In invert emulsion drilling fluid, this scheme of NPs synthesis followed the two microemulsion method as per Husein and Nassar (2008). A 1 ml of 5 M FeCl 3(aq) was added to 250 ml of the drilling fluid and mixed at 200 rpm for 24 h. In a separate vial, 1 ml of 16 M NaOH (aq) (stoichiometric amount) was added to 250 ml of the drilling fluid and mixed at 200 rpm for 24 h. The two vials were mixed and left overnight at 200 rpm and 25 o C. Two control samples were prepared, one containing the FeCl 3(aq) in the drilling fluid and another containing the NaOH (aq) in the drilling fluid, and the samples were left to mix overnight at 200 rpm and 25 o C. Finally, and in order to achieve a uniform mixture of the fluid was sheared using Hamilton beach mixer at 2500 rpm. It is worth noting that no phase separation was observed in the experimental as well as the control samples, even after a period of 4 weeks. Similar to invert emulsion drilling fluid, in-situ Fe(OH) 3 NPs were also prepared in the water based drilling fluid and tested only for LTLP fluid loss performance. 53

70 CaCO 3 NPs Calcium Carbonate NPs were prepared in-situ in invert emulsion drilling fluids using two different methods as per the reaction R2 and R5. The first method followed exactly Fe(OH) 3 NPs preparation presented in Figure 3.2. A 5 ml of 2.2 M sodium carbonate was added to 250 ml of the drilling fluid and in a separate vial 1 ml of 7.6 M aqueous calcium nitrate was added to 250 ml of the drilling fluid. The samples were left to mix overnight at 200 rpm and 25 o C. Finally, fluids were sheared at 2500 rpm again by the Hamilton beach mixer before testing. Similar to invert emulsion drilling fluid, in-situ CaCO 3 NPs were also prepared in the water based drilling fluid using the first method and tested only for LTLP fluid loss performance. The second method of in-situ synthesis of calcium carbonate NPs in invert emulsion drilling fluid employed reaction (R5). Carbon dioxide, CO 2 (99.9% purity, Praxair, Edmonton) and Ca(OH) 2 (92 % Purity, Canamara United Supply, Calgary) were used as the precursors. First, 3 g Ca(OH) 2 was added to 6 ml of water and then mixed overnight at 200 rpm and 25 o C. The calcium hydroxide solution was added to 500 ml invert emulsion drilling fluid and sheared at 2500 rpm using a Hamilton beach mixer for 30 min. Carbon dioxide, CO 2, gas was allowed into the drilling fluid sample through a sparger for min until ph changed to neutral. The ph of the invert emulsion drilling fluid was roughly estimated using a ph paper. The mechanism leading to CaCO 3 NPs formation included CO 2 transport to the water pools through the organic phase, reaction in the water pools, Brownian collisions leading to material exchange, nucleation of CaCO 3, particle growth and may be aggregation due to Brownian collisions (Bandyopadhyaya et al., 2001). Finally, to ensure uniform dispersion of the NPs a Hamilton beach mixer was used at 2500 rpm. Figure 3.3 is a schematic representation of the experimental procedure used to form the NPs as per reaction (R5). This approach has serves within borehole NPs preparation, which may reduce particle aggregation upon shearing drilling fluid through the drill bit. It may also help controlling CO 2 emissions and converting it into value added product. 54

71 Ca(OH) 2 (aq) + CO 2(g) CaCO 3 (s) + H 2 O (R5) Reaction pathways as per Soony et al. (2002) involves the following steps. CO 2(g) CO 2(aq) (R6) CO 2(aq) + H 2 O H 2 CO 3 ; ph= 4 (R7) H 2 CO 3 H + + HCO 3 - (R8) HCO 3 - H + + CO 3 2- (R9) Ca 2+ +CO 3 2- CaCO 3 ; ph= 8 (R10) Figure 3.3: Schematic of In-situ prepared CaCO 3 NPs-based drilling fluid using CO FeS NPs In-situ Iron (II) Sulfide NPs were prepared by the method presented in Figure 3.2, and only invert emulsion was employed here. First, 1 ml of 3.4 M aqueous iron (II) chloride 55

72 was added to 250 ml of the drilling fluid and in a separate vial 4 ml of 0.9 M aqueous sodium sulfide was added to 250 ml of the drilling fluid. The samples were left to mix overnight at 200 rpm and 25 o C. Finally, to ensure good dispersion product NPs, the invert emulsion mud was sheared at 2500 rpm by a Hamilton beach mixer for 30 min BaSO 4 NPs In-situ preparation of barium sulfate NPs followed the same procedure as above, and again, only invert emulsion muds were employed. First, 3 ml of 1.14 M aqueous barium chloride was added to 250 ml of the drilling fluid and in a separate vial 3 ml of 1.14 M aqueous sodium sulfate was added to 250 ml of the drilling fluid. The samples were left to mix overnight at 200 rpm and 25 o C. Finally, to ensure good dispersion product NPs, the invert emulsion mud was sheared at 2500 rpm by a Hamilton beach mixer for 30 min. 3.3 Characterization methods and techniques Particle characterization The ex-situ prepared NPs were characterized using X-ray diffraction patterns and transmission electron microscopy, whereas the in-situ prepared NPs were characterized as part of the mud cake following deposition on the filter paper using energy dispersive X-ray spectroscopy. The ex-situ prepared NPs were collected by centrifuging the aqueous colloidal suspension at 5000 rpm for 30 min to recover the NPs followed by washing several times with deionized water. The particles were left to dry at room temperature for 24 h. The dried particles were ground using a pestle and mortar before been introduced to Ultima III and Ultima IV Multipurpose Diffraction system. Ultima III operating at 40 KV and 44 ma and Ultima IV operating at 40 KV and 40 ma use Cu Kα and Co Kβ radiation respectively (Rigaku Corporation, USA) with a θ 2θ goniometer. Each scan used a 2 step size from 0 to 90 for Ultima III and 5 to 90 for Ultima IV with a counting time of 2 s/step. The structure was identified by comparing the diffractograms with spectra in the JADE program, Materials Data XRD Pattern Processing Identification & 56

73 Quantification. Ultima III and Ultima IV were used for Fe(OH) 3 and CaCO 3 based NPs structure identification respectively. The particle size distribution was determined using transmission electron microscopy, TEM. A small amount of the powder used for XRD analysis was dispersed in 5 ml of methanol using sonication and one drop of the methanol dispersion was deposited on a copper grid covered with carbon film, and was left to evaporate for 24 h. In order to avoid possible aggregation upon methanol evaporation, only a thin layer was deposited on the copper grid. The grid was then introduced to a Philips Tecni (FEI USA Inc., Hillsboro, OR) TEM equipped with 200 kv Field Emission Gun and Gatan Imaging Filter (GIF) with a slow scan CCD camera. The in-situ prepared NPs, on the other hand, were characterized following their collection on the filter cake. Filter cake of drilling fluid was dried at room temperature (~25 o C) for 4 days. The samples were then mounted and gold vapor applied to the surface of the dried filter cake to create an electrically conductive layer necessary for SEM photographs. In addition, an electrically conductive carbon particle suspension was used to glue the filter cake sample to pedestal. Oil based mud needed more time to achieve good gold coat, whereas water based mud took less time. Scanning electron microscopy (SEM) analysis was performed on a FEI ESME XL30 (Philips XL30 ESEM, USA). The instrument uses 20 kv acceleration voltage, WD= 10 mm with secondary and backscattered electron signal. The images were taken under high vacuum mode and recorded with a slow scan camera. Elemental analysis of the mud cakes was performed with the energy-dispersive X-ray spectrometry (EDX) attached to the SEM Toxicity evaluation The assessment of the environmental effects requires an evaluation of the NPs ecotoxicity. The Microtox bioassay was used to assess the toxicity of the Fe(OH) 3 NPs only. Samples were analyzed using Microtox method (EC 50 % at 15 min) in an external lab (Kaizen Lab, Calgary, Canada). The effective concentration, EC 50, is defined as the concentration that produces a 50% light reduction (García et al., 2011) and was measured after 15 min contact time. The test system measured the light output of the luminescent bacteria of the NPs sample and compared it to the light output of a control 57

74 sample containing no NPs. A difference in light output between the sample with NPs and the control was attributed to the effect of the NPs on the organisms. Microtox is a qualitative test of toxicity and the protocol of testing is shown as follows (Kaizen Lab, Calgary, Canada). Aqueous extraction of solid samples Create dilution Determine EC 50 (15 C,15 min) Pass : EC 50 75%; Non-toxic Fail : EC 50 < 75%; Toxic Emulsified water droplet measurement Water-in-oil invert emulsions with primary emulsifier were prepared using 10 v/v% water, which is the same as the drilling fluid, except for the fact that solids were not added. The water droplet diameters of the invert emulsion were measured using Morphologi G3 microscope (Malvern Instruments Inc, USA) Drilling fluid characterization The filtration properties of the different drilling fluids involved in this study were measured according to API 30-min test (API RP 13B-2,2012; API RP 13B-1,2003). Data were collected using a standard FANN filter press (Fann Model 300 LTLP, Fann Instrument Company, USA) and filter paper (pore size 2.7 µm, Fann Instrument Company, USA). The low temperature low pressure (LTLP) test was conducted according to the following procedure. A volume of 500 ml of the drilling fluid was poured into the filter press cup and 100±5 psi of pressure was applied through CO 2 supply cylinder at room temperature of 25 o C. The cumulative volume of permeate was 58

75 reported after 7.5 min and 30 min from the graduated cylinder reading. Three replicates were prepared for every sample and 95% confidence intervals are reported in the results. The smoothness of the final filter cake was reported through visual observation, while the thickness was measured using a digital caliper (0-6 TTC Electronic digital calipers model # T3506, Canada). The concentration of the NPs in permeate was correlated to iron and calcium concentration measured by an inductively coupled plasma (ICP) (IRIS Intrepid IIXDL, Thermo Instruments Canada Inc., Canada). A portable 175-mL Ofite high temperature high pressure (HTHP) filter press (OFI Testing Equipment Inc, USA) and filter paper (pore size 2-5 µm, specially hardened for filter presses, Fann Instrument Company, USA) was used to study the filtration characteristics of the mud at differential pressure of 500 psi and temperatures of 177 C (350 o F). Fann LTLP and Ofite HTHP filter presses are shown in Figure 3.4. a) b) Figure 3.4: Drilling fluid loss apparatus for a) LTLP and b) HTHP tests. It should be noted that the area of the filter paper used in the HTHP filter press is onehalf the area of the standard filter press. Therefore, the volume of filtrate collected in 30- min is typically reported as double. Commercial invert emulsion drilling fluid without NPs and LCM (Gilsonite) and with 1.6 wt% LCM only were considered as baseline drilling fluids for comparative evaluation of API and filtration experiments. Invert emulsion 59

76 drilling fluids containing NPs and 1.6 wt% LCM or NPs only were considered as the nano-based drilling fluids of study. Fann Model 140 mud balance (Fann Instrument Company, USA) was used to measure the mud density. During the measurement care was taken in order to eliminate any errors due to air entrapment. The ph measurements were performed using ph papers (0-14) (VWR international, Calgary, Canada). Several readings were collected in order to ensure precision, despite the limitations of ph determination using ph paper, since a ph meter could not be inserted in the mud. In addition, and in order to provide more reliability for the method, hydrated lime, similar to the one used in drilling fluid, was dissolved in water at the same concentration as the water in the drilling fluid, and its ph was measured using ph meter (Model: AccumetAB15+,Fisher Scientific, Toronto, Canada ) and ph papers. A rotational Fann 35A viscometer (Fann Instrument Company, USA) was used to measure the rheological properties of the drilling fluid at six different speeds as shown in Figure 3.5. Figure 3.5: Fann Model 35A viscometer for measuring viscosity. A volume of approximately 350 ml of the fluid was poured into the viscometer cup, and the mud was sheared at a constant rate in between an inner bob and outer rating sleeve. The system was left to rotate at a certain rpm until reaching the steady state reading for 5 min. The readings were collected at 600, 300, 200, 100, 6 and 3 rpm. These experiments were conducted at room temperature. The dimensions of bob and 60

77 rotor were chosen such that the dial reading on the viscometer is equivalent to apparent viscosity in centipoises at rotor speed of 300 rpm. The apparent viscosities for all rotor speeds were calculated using equation (E3.1) below (Fann 35 viscometer manual, 2008): Apparent/ Effective viscosity, μ a = 300 (E3.1) N where N is the rotor speed (rpm) and is the viscometer dial reading ( o ). The shear rate can be calculated as per equation (E3.2) (Fann 35 viscometer manual,2008). Shear rate, sec -1 = N (E3.2) The plastic viscosity and yield point are found using the following equations (Fann 35 viscometer manual, 2008): Plastic viscosity, μ p = ϴ ϴ 300 (E3.3) Yield point, Y p = ϴ μ p (E3.4) where μ p plastic viscosity (cp), Y p yield point (lb f /100ft 2 ), ϴ 600 and ϴ 300 are the dial readings at 600 and 300 rpm, respectively. Gel strength of the drilling fluid was measured at lower shear rate after the drilling mud is static for a certain period of time. The readings at 3 rpm were taken after 10 sec and 10 min following stirring the drilling fluid at 600 rpm for 5 min. The first reading noted after the mud is in a static condition for 10 sec is called 10 sec gel strength. The second gel strength noted after 10 min is called 10 min gel strength. Gel strength is usually expressed in pressure unit lb f /100ft 2. The difference between the initial gel strength and those taken after a 10 min test period were used to define how thick the mud would be during round trips. Lubricity test is designed to simulate the speed of rotation of the drill pipe and the pressure the pipe bears against the wall of the bore hole (OFITE lubricity test manual, 2011). It also predicts the wear rates of mechanical parts in known fluid systems. Lubricity property of the NP-based drilling fluid was evaluated by OFITE Lubricity Tester (Part no: , serial: 07-09, Houston, USA) at 150 inch-pounds of torque which are 61

78 applied to two hardened steel surfaces, a block and ring rotating at 60 rpm rotational speed as shown in Figure 3.6. Figure 3.6: OFITE drilling fluid lubricity tester. The test sample is completely immersed between the ring and block. The apparatus runs for 5 min in order to coat the metal test pieces with the sample fluid. The torque adjustment handle is then turned until 150 inch-pounds of torque have been applied to the test block. The machine again runs a 5 min stabilization period. A friction coefficient reading is then taken. Additional readings are taken every 5 min until three consecutive readings agree within ±2 units. The drilling fluid lubricity coefficient can be calculated using the following equation as given in the Ofite manual (Ofite lubricity tester manual, 2011). Coefficient of friction = lb forceto turn the ring lb torque load applied = Meter Reading 100 (E3.5) Coefficient of Friction (CoF) is used to quantify how readily two surfaces slide in the presence of a lubricant or oil. It is a key factor which directly affects the torque and drag. The lower the value of the coefficient of friction, the higher the lubricity, or vice-versa. The torque reduction at a given load can be calculated using the following equation. (AL BL ) Percent torque reduction at given load = x 100 A where A L = Torque meter reading of untreated mud (inch-pounds) B L = Torque meter reading of treated mud (inch-pounds) L (E3.6) 62

79 Chapter Four: Results and Discussion Initially the experimental analysis was performed on the base drilling fluid, mostly invert emulsion containing all ingredients, e.g. organophilic clays, primary and secondary emulsifiers, brine, etc. except for the lost circulation materials (LCMs), to understand the nature of the fluid loss, and later with drilling fluid containing conventional LCMs, i.e. Gilsonite. The next step was to test these fluid systems in the presence of in-house prepared nanoparticles (NPs), and commercial Fe 2 O 3 NPs. Concentrations between 1-4 wt% NPs were used depending on the stability of the NPs in the drilling fluid (Husein et al., 2012 a&b; Zakaria et al., 2012). Needless to say that low concentrations were targeted to study large-scale application. Results pertaining to the detailed preparation and performance of Fe(OH) 3 NPs are presented first. Then, the preparation and performance of CaCO 3 NPs were considered in details, due to the wide application of CaCO 3 particles in drilling fluids (Manea, 2012; Simon et al., 2010; Whitfill at al., 2003). Finally the preparation and performance of BaSO 4 and FeS NPs were considered in order to prove the applicability of the in-house preparation method developed in this work to other NPs. It should be noted also that BaSO 4 and FeS are widely used as weighting material in drilling fluids (Scott and Robinson, 2010; Moore and Cannon, 1936). In all cases the NP-based fluids were compared with the corresponding control DF samples. The use of NPs to increase the mud density, while minimizing sagging was demonstrated by other groups (Amanullah et al., 2011). Therefore, the characteristics of NP-based DF were evaluated by measuring mud weight, ph, viscosity, gel strength, API LTLP and HTHP filter tests and lubricity as described in Chapter Fe(OH) 3 Nanoparticles (NPs) Characterization The structure of the ex-situ prepared Fe(OH) 3(s) NPs was determined using X-ray diffraction (XRD) patterns, whereas its particle size distribution was evaluated using TEM photographs. Detailed particle characterization is provided herein. 63

80 4.1.1 X-ray diffraction analysis The X-ray diffraction pattern of the ex-situ prepared NPs shown in Figure 4.1 indicates no evidence of strong distinct peaks which would be expected from a crystalline material. This said, the most likely product as suggested by the figure is Fe(OH) 3(s). The peak maximum around 2θ= 35 can be attributed to the presence of aggregates dispersed in an amorphous phase (Zakaria et al., 2012). Streat et al. (2008) has also prepared ferric hydroxide using ferric chloride and stoichiometric quantity of sodium hydroxide in deionized water and reported the same XRD pattern. Figure 4.1: X-ray diffraction pattern for the ex-situ prepared iron-based NPs. Reaction ph might affect the final nature of the iron oxide/hydroxide product. The optimum ph for the precipitation of Fe(OH) 3(s) is found 5 (Zakaria et al., 2012). Liu et al. (2005) reported the same initial ph level of the precipitated amorphous Fe(OH) 3 prepared from aqueous FeCl 3 and NaOH precursors. Phase transformation of Fe(OH) 3 gel to α-fe 2 O 3 particles was impacted by the ph range. In a different study, Cai et al. (2001) found that at room temperature the reaction ph affected the crystallinity of iron oxide material. They reported narrow and distinct peaks for 1.5 ph< 4. At ph= 4 there were two broad and less intense peaks similar to the ones appearing in Figure 4.1 suggesting poor crystallinity. At ph 6, crystallinity was re-gained. It is to be noted that 64

81 amorphous iron (III) hydroxide can transform into α-fe 2 O 3, β-feooh or α-feooh with the change in reaction temperature (Nassar and Husein, 2007a). The X-ray diffraction pattern of a filter cake collected following LTLP test of a drilling fluid containing ex-situ prepared Fe(OH) 3 NPs and organophilic clays is shown in Figure 4.2. The pattern in Figure 4.2 suggests that Fe(OH) 3 NPs acted as intercalating agents and had entered into the crystallite layers of bentonite clay. It is believed that such a structure of nanometal-clay composite could improve drilling fluid properties; including loss prevention and wellbore strengthening. In addition, this structure suggests good compatibility, dispersion and communication between the NPs and the rest of the drilling fluid constituents, which ultimately could offer better functionality than regular bentonite clays. NPs embedded randomly on the surface of clay particles promote gelation of the bentonite particles (Baird and Walz, 2006; Lee et al., 2010). Similar observation was also reported by Fernandez et al. (2010) using acrylamide polymer with bentonite clays. An important outcome of good gelation is inhibition of clay swelling as reported by Mei et al. (2011). Figure 4.2: X-ray diffraction pattern of ex-situ prepared Fe(OH) 3 NPs collected on the filter paper. 65

82 4.1.2 Water droplet size distribution Emulsion samples were prepared by mixing water with the similar type base oil (low aromatic oil) and the primary emulsifiers used in the drilling fluids formulation but no solids, i.e. bentonite, were used. The water droplets were observed in the oil phase by a microscope. It was clear that 10/90 (V water/v oil) contained droplets size from 1-30 µm with mean droplet diameter at 20 µm as shown in Figure 4.3. Water-in-oil (w/o) microemulsions have been demonstrated as a very versatile and reproducible method that allows control over nanoparticle size and yields particles with a narrow size distribution (Lopez-Quintela, 2003), by virtue of their nanometer scale water pools. In principle, invert emulsion drilling fluid can be employed in a similar manner to prepare NPs. However, knowing the fact that invert emulsions typically contains much larger water pools, as shown in Figure 4.3, mixing becomes a very important parameter. In studies by Anisa and Nour (2010) and Fjelde (2007), it was shown that stirring speed largely affects the droplet size distribution in (w/o) emulsions. Higher shearing and duration of stirring lead to a very tiny droplets, which can act as nanoreactors. In this works, the NPs were stirred at 200 rpm during preparation and sheared in the drilling fluid at 2500 rpm, which enabled them to accommodate into the water pools effectively. Figure 4.3: Particle size distribution histogram of water droplet obtained from a waterin-oil emulsion by dispersing water into base-oil with the aid of a primary emulsifier. 66

83 As can be seen in Figure 4.3, most of the droplets were µm in diameter. It should be noted, nevertheless, that the detection limit of the instrument used was down to 0.5 μm in size. Therefore, Figure 4.3 should be considered with caution. Similar experiment has been performed by Fjelde (2007) for 25/75 and 5/95 (V water/v oil) emulsions in the presence of primary and secondary surfactants and water droplet sizes between 3-50 μm were reported for both mixes at different temperatures. Generally, the water droplets in an emulsion may vary in size from less than 1 μm to more than 1000 μm (kokal, 2006). Typically in oil based drilling fluids, macroemulsion, which may have droplet sizes in the range from μm (Kokal, 2006; Bumajdad et al., 2011), are used. Generally microemulsions consist of nano-sized water pools dispersed within the bulk organic phase which act as nanoreactors for the chemical reduction of the metallic precursors and metallic nanoparticle preparation (Kitchens,2004). Size of the particles can be controlled by surfactant/co-surfactant type, concentration of the reagents and water/surfactant molar ratio (Zielińska-Jurek et al.,2012). The total concentration of metal ions under the present experiment is so small that the influence of water droplet size has no great influence on the nanoparticles formation and growth. Moreover, the primary and secondary surfactant rich stabilized invert emulsion fluid limit particle growth and agglomeration of metal particles in water pools and renders particle sizes in the nm scale (Husein and Nassar, 2008) Size distribution of ex-situ prepared Fe(OH) 3 NPs The TEM photographs and the corresponding particle size distribution histogram for the ex-situ prepared Fe(OH) 3 are shown in Figure 4.4. The histogram shows a spread in the size distribution with most of the population falling in the range between 1-30 nm. The photograph confirms that there is good degree of agglomeration, which must have resulted from the high degree of collision between the precipitated particles while shearing, especially since no surfactants were added to the aqueous phase. 67

84 a) TEM Photographs Particle Sizes from 1 to 120 nm b) Particle Sizes from 1 to 30 nm 100 nm Particle size (nm) Figure 4.4: TEM photographs and corresponding particle size distribution histograms of the ex-situ prepared Fe(OH) 3 NPs in the range between a) nm and b) 1-30 nm. Dispersing the ex-situ prepared NPs by ultrasonication in methanol for 10 min before deposition on the TEM grid did not seem to eliminate aggregation, despite the fact that the NPs were not found to exhibit magnetic properties. Therefore, it is concluded that this agglomeration at room temperature is not due to magnetic attraction, but rather due to the high surface energy of the particles (Bumajdad et al., 2011). Once mixed with the drilling fluid, the surfactant rich stabilized invert emulsion, or water-based muds, limits the aggregation of the ex-situ prepared particles, especially since the concentration of NPs in the drilling fluid is kept very low, < 5 wt%. On the other hand, in-situ prepared NPs are expected to be very well dispersed by virtue of the surfactant component of the drilling fluid mix. The wide size distribution of particles has prompted an investigation on the filtration characteristics of LCM-free NP-based drilling fluid. The results of this investigation are detailed below Determination of particle size of in-situ prepared Fe(OH) 3 NPs When NPs are prepared in-situ within invert emulsion drilling fluids, it is not easy to separate the particles for characterization. Alternatively, these particles could be characterized following their collection on the mud cake. SEM images of the mud cake 68

85 without and with NPs are shown in Figure 4.5a,b, respectively. The observed morphologies of the two samples have some distinct features. The mud cake with NPs was fully intact and displayed a very smooth surface with no visible cracks at even 48 times magnification. It is worth noting that the cake surface was covered with Fe(OH) 3 particles, as was visually confirmed from the reddish brown color of the surface. The texture of the mud cake in the absence of NPs was rough and full of cracks. It is, therefore, plausible to believe that the voids and gap of pores were effectively filled with NPs, and NPs acted as an effective filling agent. This said, one should also keep in mind the effective intercalation between Fe(OH) 3 NPs and the organophilic clays reported earlier. These observations are very important for the explanation of fluid loss prevention and lubricity reported in this study as well as wellbore strengthening reported in a recent study, which employed the same method and NPs developed in this study (Nwaoji et al.,2013; Nwaoji,2012). Lastly, effective adsorption/deposition of Fe(OH) 3 NPs on the organophillic clays forming the cake may also contribute to a surface chemical reactivity, which can provide further sealing. Lai et al. (2000) reported that Cu 2+ ions were effectively adsorbed onto iron oxide-coated sand. Finally, it is important to note that mud cakes tested were LCM free. a) b) Crack Figure 4.5: SEM Images at 48x magnification of mud cakes collected following API LTLP filtration tests a) without NPs, b) with 1 wt% in-situ NPs (90/10(v/v) oil/water invert emulsion mud, no LCMs). 69

86 The elemental distribution mapping of EDX for the sample of mud cake without NPs and mud cake with NPs are depicted in Figure 4.6. Through elemental analysis it was determined that 0.7 wt% of iron ion was found on the mud cake. Results indicated that iron ions could trap into the micropores and mesopores of the cake-containing clays. It can be also attributed to diffusion of adsorbed metal species from the surface into the nanopores, which are the least accessible sites of adsorption. This is believed to contribute to effective sealing while filtering. Figure 4.6: Elements contained in mud cake a) without NPs, b) with Fe(OH) 3 NPs as per EDX analysis. 4.2 Drilling fluid Characterization Stability of NP-based Fluid Visual observation was used to assess the stability of the NP-based fluids. Stability against agglomeration and sagging relates here to the shelf life of the NP-based fluid. Figure 4.7 shows photos of samples representing the original drilling fluid (90 vol. oil/10 vol. water) invert emulsion samples without and with in-situ prepared Fe(OH) 3 NPs. The photos show no sign of sagging or aggregation even after 4 weeks of setting at room temperature and confirm that, at the concentration of the added NPs, no agglomeration or sagging takes place. Therefore, no extra additives were required to stabilize the NPbase drilling fluid. The stability of an invert emulsion system containing dispersed particles can be attributed to a steric effect conferred by adsorbed materials, mostly 70

87 surfactant molecules, onto the particles (Husein and Nassar, 2008; Nassar and Husein, 2007a). Careful evaluation of the system stability as a result of NPs addition showed that no sagging was experienced for the different NPs considered in this work; including Fe(OH) 3, CaCO 3, BaSO 4 and FeS, up to 5 wt% and stable samples are obtained for several weeks. This applies to both, in-situ prepared NPs and NPs prepared ex-situ and then mixed with the drilling fluid. a) b) NP-based Fluid Original Drilling Fluid NP-based Fluid Original Drilling Fluid Figure 4.7: Photos comparing NP-based and original invert emulsion drilling fluids (Invert emulsion (90 vol. oil/10 vol. water); 1 wt% Fe(OH) 3 in-situ prepared NPs). NPs that grow or agglomerate to sizes beyond the stabilization capacity of invert emulsion fluid might settle under gravity, which was not apparent in the above photos. This suggests that the mixing provided during the preparation of in-situ and ex-situ NPs as well as during mixing of ex-situ prepared NPs with the drilling mud was sufficient to provide dispersion at a molecular level, which, in turn, leads to the formation of very small particles that are well dispersed and stabilized in the rest of the fluid. As stated earlier, adsorption of emulsifiers on the surface of these particles helps further stabilizing them within the fluid. A qualitative assessment of the stability of the nanobased fluid was done by checking its rheology behavior after 1 month which is detailed in the rheology section LTLP Filtration Filtration property is dependent upon the amount and physical state of colloidal materials used in the mud. When mud containing sufficient colloidal material is used, 71

88 fluid loss can be minimized as these materials will deposit and contribute to cake formation, which increases resistance for fluid permeation. This resistance is highly dependent on the structure and integrity of the filter cake. Details on the integrity and structure of the cake were provided earlier. On the other hand, the spurt loss of the drilling fluid is considered as one of the sources of solid particles and particulate invasion to the formation, which can cause serious formation damage as a result of internal mud cake formation in the vicinity of the wellbore (Amanullah et al., 2011; Al- Hitti et al, 2005; Peng, 1990). Internal pore throat blockage may create a flow barrier which reduces oil and gas flow. Moreover, higher particle flocculation in drilling fluid leads to a thicker mud cake which increases the probability of differential sticking and stuck pipe problems (Amanullah et al., 2011). This highlights the importance of using low concentration of dispersed NPs in fluid design with virtually no spurt loss, low filtrate volume and good quality filter cake Commercial NPs At first, commercial iron oxide NPs were introduced into the commercial invert emulsion drilling fluid as per literature procedure (Agarwal et al.,2009; Amanullah et al., 2011; Srivatsa, 2010; Abdo and Haneef,2010), which involved mixing at 2500 rpm for 30 min. This experiment served as bench marking. The performance towards fluid loss prevention was very poor as can be seen in Table 4.1. It is to be noted that the original drilling fluid (DF) was completely LCM free. A large amount of small fish eyes (lumps of agglomerated commercial NPs) on the NP-based mud cake was clearly seen, as shown in Figure 4.8. It appears that, even under the high shear mixing used to prepare the inhouse NPs, commercial NPs did not seem to effectively disperse into the drilling fluid. This, in a way, limited their interaction with the clays and resulted in a poorly structured filter cake. The mud cake in the absence of NPs was provided for comparison. The thickness of the mud cake developed upon filtering commercial NP-based drilling fluid was 0.76 mm, whereas the one obtained from filtering the invert emulsion mud was 0.31 mm. 72

89 Table 4.1: API LTLP loss of drilling fluid in the presence and abscense of 1 wt% commercial Fe 2 O 3 NPs. NPs were thoroughly mixed with the invert emulsion drilling fluid. No LCMs added to both samples. Samples Types 90:10 (v/v) Oil: Water Commercial NPs Used (20-40 nm) Fe 2 O 3 /FeOOH Time (min) LPLT Fluid Loss (ml) DF DF with 1 wt% NPs Fluid Loss Reduction % ± ± ± ± fish eyes Commercial NP-based mud cake Mud cake without NPs Figure 4.8: Mud cake of drilling fluid with commercial NPs and without NPs In-house prepared Fe(OH) 3 NPs Following the hypothesis outlined earlier; in-house prepared NPs may better interact with the drilling fluid, especially the in-situ formed ones, in-house prepared Fe(OH) 3 NPs were formulated inside, or added to, the drilling fluid. In-house Fe(OH) 3 NPs at 1 wt% and size varying from nm had better plugging performance than commercial Fe 2 O 3 NPs and will be detailed in the fluid loss experiments. Fish eyes, which appeared in the mud cake containing the commercial NPs, were minimized in the presence of the in-house; both ex-situ and in-situ, formulated NPs as can be seen 73

90 in Figure 4.9 and Moreover, NaCl, which is a by-product of the Fe(OH) 3 formation reaction, is commonly used as a bridging solid to prevent clay swelling and clay dispersion, which, in turn, lead to the minimiiinm clay related formation damage (Mohan et al., 1993; Crowe,1990). Generally, the characteristics of the resultant filter cake depended on the degree of peptization or flocculation of the suspension. Stable (peptized) suspensions form dense and compact sediments, while flocculated suspensions form more voluminous sediments and particles are associated in the form of a loose, open network (Smith and Hartman, 1987). Filter cake formed from stable dispersion of NPs is relatively impenetrable, and hence, creates more resistance to flow in comparison to that formed from flocculated commercial NPs. This might explain why in-house prepared NPs showed better performance. In-house prepared NPs are better dispersed in the drilling mud. Therefore, they effectively adsorbed into the pore space of clay platelets and formed well dispersed plastering effect on the filter paper. This implies lower penetration of drilling fluid into the formation and, hence lesser damage to the formation. In-house prepared NPs progressively built up on the surface of the filter cake and acted as a shut off valve. Effective mud cake resulted in much lower fluid loss as can be clearly seen in Table 4.2. Table 4.2: Comparative study of API LTLP fluid loss of drilling fluids with 1.6 wt% conventional Gilsonite LCM, and 1 wt% in-situ and ex-situ prepared NPs. Samples Types 90:10 (v/v) Oil: Water Time (min) *Fluid loss reduction, %. LTLP Fluid Loss (ml) DF DF +LCM DF+LCM with 1 wt% ex-situ NPs DF+LCM with 1 wt% in-situ NPs ± ± ± ± ±0.1 (9%*) 1.1±0.1 (72%*) 0.5±0.2 (87%*) Cake thickness, mm Original drilling fluid (DF) without NPs and LCM and drilling fluid with 1.6 wt% LCM were considered as a baseline for comparative evaluation of fluid loss property of the ex-situ 74

91 and in-situ prepared nanobased fluid. Based on the original DF, fluid loss over a period of 30 min decreased by 9% for the drilling fluid containing 1.6 wt% LCM only, while it decreased by 70% for the drilling fluid containing 1 wt% ex-situ prepared Fe(OH) 3 NPs and by more than 80% for the drilling fluid containing the in-situ prepared Fe(OH) 3 NPs. Both ex-situ and in-situ drilling fluid samples contained 1.6 wt% Gilsonite LCM. In-situ prepared NPs, which, as stated earlier, immediately adsorb onto neighbouring clay platelets when squeezed through the filter cake by virtue of their high dispersion, fill the pores and the gaps of clay network and, hence tremendously lower the fluid loss compare to the ex-situ prepared NPs. On the other hand, for the typical LCM, particles larger than pore opening cannot enter the pore at first and might be swept away by the mud stream, of course under dynamic drilling. During spurt loss period (t< 7.5 min), mud particles attempt to flow with the filtrate through the filter paper. The emulsion droplets provide sufficient surface area for the water-containing NPs to spread on the mud cake. This may have resulted in NPs bridging across pore throats to form the external mud cake immediately, and thus lowering the spurt loss. Iron oxides/hydroxides have affinity for negative charges (Follett, 1965), while the edges of the betonite clay are negatively charged (Xu et al., 2005; Lai et al., 2000; Follett, 1965). This may explain the high particle-clay interaction during filtration (Xu et al., 2005; Lai et al., 2000; Follett, 1965). Fluid loss control of drilling muds using similar approach was not reported in the literature. Most of the literature on NP-based drilling muds considered water based muds employing commercial NPs, and loss reduction of 40% was reported for 1-30 wt% NPs (Amanullah et al., 2011; Srivatsa, 2010; Cai et al., 2011). Using similar explanation to Aston et al. (2002), NPs probably acted at the interfacial region between the emulsion droplets and the oil phase when pressure is applied during filtration and made the region viscous. This phenomenon could slow down the flow of oil through the cake and thereby lower the fluid loss. Moreover, there could be an additional effect from NPs acting as bridging agents between long chain hydrocarbons, including those of LCM molecules, in the invert emulsion drilling fluids. 75

92 The above results are particularly important when drilling in shale formations. Even though shales have macro to nano pores, shales are very sensitive to water loss since they tend to swell easily (Chenevert and Sharma,2009). Conventional LCMs will not be able to block the nanopores due to their micron sizes. Therefore, smaller particles, i.e. NPs, are needed to better fit the nanopores. In order to prevent drilling and completion problems, mud cake quality and build up characteristics are also very important. Figure 4.9 includes photographs of the mud cake formed in the presence and absence of NPs. Compared with LCM based cake, the NP-based drilling fluid produced thin mud cake less than 1 mm. The NP-based DF deposited a fine thin layer of iron (III) hydroxide NPs on the cake surface. Addition of NPs did not cause an increase in the thickness of the mud cake, especially since small concentrations of NPs were used in fluid formulation and these NPs are believed to be located on the top of the clays and eventually filled the gap or holes in the clay platelets. The NPs are subsequently captured within the clay layers. This multiple layer structure provides much better sealing, prevents further flow through the pores, and subsequently lower clay deposit and thinner filter cake. During filtration clays provided disordered stacking and displayed the highest permeability. NPs reduced this roughness of clay surface by the thickness of the deposit. It could be associated with dispersion ability of nanoparticles to be well-distributed more effectively on the surface of bentonite clays or intercalation of NPs in clay layers provided lower permeability. This eventually decreases the volume of the cake leads to a minimum amount of fluid in the pores. Moreover small concentrations of NPs were used in fluid formulation. On the other hand, large sized LCM could not lodge in the porous space of the cake and the cake exhibited sufficient porosity to permit continued flow through it as filtration proceeds. This, in turn, led to more clay depositing onto the cake and particles accumulation. Moreover, Figure 4.9 c-d shows that a layer of NPs was the last to deposit on the cake surface leading to crack-free and smooth surface. Thin filter cake suggests a high potential for reducing the differential pressure sticking problem while drilling. 76

93 a) b) c) d) Thickness= 0.31mm Thickness= 0.76 mm Thickness= 0.52 mm Thickness= 0.44mm Figure 4.9: Mud Cakes with thickness of a) DF only, b) DF+LCM, c) DF +LCM with 1 wt% ex-situ NPs, and d) DF+LCM with 1 wt% in-situ NPs. Because the fluid loss performance is improved dramatically with the Fe(OH) 3 NPs additives, it raises the question as to whether conventional LCMs are still needed to control the fluid loss, especially in light of the fact that NPs displayed a relatively wide size distribution, at least the reported ex-situ prepared ones. These measurements suggest that a wide size range of NPs can be used as substitutes for conventional LCMs in the mud, e.g. Gilsonite. The hypothesis was larger size NPs would contribute to blocking large formation pores and help bridging large voids, and once a primary bridge is established, successively NPs, down to few nm, are trapped and thereafter stop the filtrate from invading the formation. The filtration properties of a drilling fluid with NPs only also consider the wall/cake building ability of the NPs with the solid components of drilling fluid such as clays. The results of the API low temperature low pressure LTLP experiments are shown in Table 4.3. An interesting observation was that a wide range of NPs size distribution gave the lower filtrate volume than the Gilsonite LCM. A reasonably low fluid loss value and thin mud cake with a thickness of less than 1 mm significantly improved the performance of the NP-based drilling fluid. These results are summarized in Figure

94 Table 4.3: API LTLP fluid loss comparing drilling fluid and drilling fluid with Gilsonite LCM as base cases with drilling fluid samples containing the in-house prepared Fe(OH) 3 NPs only with no LCM. Samples Types 90:10 (v/v) Oil: Water Time (min) *Fluid loss reduction, %. LTLP Fluid Loss (ml) DF DF +LCM DF with 1 wt% ex-situ NPs DF with 1 wt% in-situ NPs ± ± ± ± ±0.1 (9%*) 1.25±0.2 (68%*) 0.9±0.2 (77%*) a) b) c) d) Figure 4.10: Mud Cakes of a) DF only, b) DF+LCM, c) DF with 1 wt % ex-situ NPs and d) DF with 1 wt % in-situ NPs Filtrate Characterization Loss of fluid from invert emulsion drilling muds usually allows oil and chemicals into the formation. In order to provide a measure of how much NPs seeped through the filter cake during API LTLP filtration, the concentrations of iron and calcium in the filtrate were determined using inductively coupled plasma (ICP). In the total filtrate volume, the Fe(OH) 3 NP-based fluid reduced the calcium content 500 times relative to the drilling mud alone. It should be noted that typically the aqueous phase of the invert emulsion drilling fluids contain calcium hydroxide in order to control alkalinity (Chilingarian and Vorabutr, 1983). On the other hand, no iron was found in the original drilling fluid or the NP-based drilling fluid, as shown in Table 4.4. The results can be attributed to the fact that clays are negatively charged and adsorbed species with high affinity to negative charges such as iron oxide/hydroxide (Xu et al., 2005; Lai et al., 2000; Follett, 1965), as discussed earlier. Therefore, NPs provided bridges between the clay particles reducing 78

95 the area available for the fluid seepage and hence forcing Ca 2+ ions to adsorb onto the negatively charged clays. Table 4.4: ICP results of the filtrate collected following API LTLP to determine the Ca and Fe content. Filtrate Samples of Drilling fluid (DF) Without NPs mg (In total volumes) Ca Content Fe Content 478 Nil With 1 wt % in-situ NPs 0.87 Nil Those NPs interact with the formation and eventually plug the pore either internally or externally, preferably. If, on the other hand, it blocks the pore channel, formation damage may occur and oil and gas production will be interrupted. ICP results, together with the fact that filter cakes were thin, suggest only external plugging took place. In clays, often Na + or Ca 2+, are too large to be accommodated in the interior of the lattice and therefore may be easily exchanged by other cations when available in solution (Deriszadeh,2012). NPs either ex-situ or in-situ could exchange cations with clays and locate on the exterior surface and near the pore openings are kinetically more accessible than the interior pore wall. Therefore NPs bridge across pore throats to form the external mud cake immediately HTHP Filtration The HTHP API filtration test simulates drilling in deep formation, where both the temperature and the pressure of formation and the drilling fluid may reach high values. High temperatures may alter the size, identity and surface morphology of the Fe(OH) 3 NPs (Agarwal et al., 2009; Balek and Šubrt, 1995). This may ultimately lead to reducing the NPs effectiveness. Generally, nanoparticle aggregation and the formation of large irregular particles can be captured by visual analysis of the filter cake. The results 79

96 shown in Table 4.5 and Figure 4.11 provide details on fluid loss reduction and sealing potential of the filter cake for invert emulsion muds. Based on the original DF, fluid loss over a period of 30 min decreased by 24% for the drilling fluid containing 1.6 wt% LCM only, while it decreased by 53% for the drilling fluid containing 1 wt% ex-situ prepared Fe(OH) 3 NPs and 61% for the drilling fluid containing the in-situ prepared Fe(OH) 3 NPs. In this experiment, both ex-situ and in-situ NP-based drilling fluids contained 1.6 wt% Gilsonite LCM. The better dispersed in-situ prepared NPs exhibited lower mud cake thickness than ex-situ prepared NPs as shown in Figure Generally, the higher loss of the drilling mud with and without NPs or LCMs when compared with low temperatures is attributed to the lower viscosity of the fluid at 177 o C. Cake thickness is proportional to filtration loss (ASME, 2005). As the mud is not being circulated, the filter cake grows undisturbed with the filtrate rate. Table 4.6 shows fluid loss reduction and mud cake thickness under API HTHP conditions. As temperature and pressure go up, lower mud cake thickness in presence of Fe(OH) 3 NPs is obtained. Similar observations were reported by Javeri et al.(2011) and Paiaman and Al- Anazi,(2008). It is true that in the absence of NPs and LCMs filter cake displayed low thickness, but it should be noted that the filter cake was not effective towards filtrate reduction. NPs increase the tortuous flow path and travel time of the fluid to pass through the filter cake and lower the fluid loss. In the presence of NPs filtration rate became slow probably due to the high level of interaction between the NPs, Gilsonite and clays, which led to effective bridging even at high temperature. In addition, and as noted by Aston et al. (2002), water droplets with sizes 5.5 μm tend to bridge the 3 μm pores on the filter paper. At the high temperatures encountered in this experiment, water pools may coalesce to form larger droplets. At the low concentration of NPs it is more likely that the particles interacted with the rest of the mud constituent rather than merely aggregating. Moreover, temperature affects clays by changing the orientation of the adsorbed water pools in the clay matrix. The rigid bonding of water may decrease dispersion of the clay and form a more porous filter cake which allows a greater filtrate flow at high temperature (Fisk and Jamison, 1989). 80

97 Table 4.5: HTHP filtration property of different drilling fluid samples. Samples Types 90:10 (v/v) Oil: Water Time (min) *Fluid loss reduction,% HTHP Fluid Loss (ml) DF DF +LCM DF with 1 wt% ex-situ NPs DF with 1 wt% in-situ NPs 7.5 9± ±0.2 2± ± ±0.1 9±0.1 (53%*) 7.5±0.2 (61%*) Cake thickness, mm LCM+NPs (In-situ) Filter cake LCM+NPs (Ex-situ) Filter cake LCM Filter cake No LCM or NPs Filter cake Thickness= 1.3 mm Thickness= 2.7 mm Thickness= 7.3 mm Thickness= 1.7 mm Figure 4.11: Filter cakes obtained following API HTHP tests on invert emulsion drilling fluids with and without Fe(OH) 3 NPs and Gilsonite LCMs. 81

98 Table 4.6: Effect of operating conditions of API filtration test on mud cake thickness with and without Fe(OH) 3 NPs and Gilsonite LCMs. Temperature Mud cake thickness (mm) and Pressure DF DF +LCM DF with 1 wt% DF with 1 wt% insitu ex-situ NPs+LCM NPs+LCM 25 C,100 Psi (2.5*) 0.52 (1.7*) 0.44 (1.4*) 177 C,500 Psi (4.3*) 2.7(1.6*) 1.3 (0.8*) *Thickness improvement, x times compared to DF In a similar manner, one run with NPs in the absence of the Gilsonite LCM was performed. The results are shown in Table 4.7. The data on fluid loss at 30 min show that in the absence of LCMs, the NPs are performing better. Based on the original DF, fluid loss over a period of 30 min decreased by 79% for the drilling fluid containing 1 wt% ex-situ prepared Fe(OH) 3 NPs, while it decreased by 86% for the drilling fluid containing 1 wt% in-situ prepared Fe(OH) 3 NPs. This observation can be attributed to the fact in the absence of LCMs there seems to be higher interaction between the NPs and the clays, which resulted in better sealing and more effective filter cake. Table 4.7: HTHP fluid loss of different drilling fluid samples in the presence and absence of Fe(OH) 3 NPs. No LCMs were added. Cake Thickness at 30 min. Samples Types 90:10 (v/v) Oil: Water Time (min) *Fluid loss reduction, %. DF HTHP Fluid Loss (ml) DF with 1 wt% ex-situ NPs DF with 1 wt% insitu NPs 7.5 9± ±0.1 4±0.1 (79%*) 2.7±0.2 (86%*) Cake thickness, mm

99 In-situ NPs Mud cake NP-free DF Mud cake Ex-situ NPs Mud cake Thickness 1.1 mm Thickness 1.7 mm Thickness 2.1 mm Figure 4.12: Mud cakes obtained following API HTHP tests on invert emulsion drilling fluids with in-house prepared NPs only. No LCMs added. LCMs seem to consume NPs, which would otherwise interact with the mud cake to a better extent than the interaction of the NP-LCM combination. The better dispersed insitu prepared NPs exhibited lower mud cake thickness than ex-situ prepared NPs as shown in Figure When subjected to high temperatures, NPs are likely to maintain stability and dispersion in the water-in-oil emulsions. Agarwal et al. (2009) used nano CuO with nm diameters and nano alumina with nm diameters in invert emulsion drilling fluids and showed that drilling fluids maintain their stability even at 175 o C. It appears that when NPs are mixed with drilling fluid, clay suspensions may bind with NPs resulting space-filled structure. A sol-gel formation may be induced, which finally blocks fluid flow through the filter media, upon filtration. Addition of inhouse prepared Fe(OH) 3 NPs, increases the ionic strength of the fluid, due to the formation of NaCl by-product, which causes stronger interaction with the clays during HTHP filtration (Agarwal et al., 2009). As discussed earlier, the elimination of spurt loss observed in these experiments may reduce formation damage, and thin mud cakes could possibly reduce stuck pipe problems (Chilingarian and Vorabutr, 1983) Effect of high shear on fluid loss control High degree of mixing and shearing of the drilling fluid is essential to form NP-based drilling fluid using the in-house preparation technique, as described earlier. This step is important whether the particles are prepared in-situ or ex-situ. Shearing device may 83

100 significantly increase the dispersed phase fraction and dampens coalescence by breaking agglomerated particles (Amanullah, 2011). Hamilton beach three blade high speed mixer was used in addition to vigorous agitation of fluid during preparation. This inexpensive equipment is used mostly in food processing. High-shear mixers provide rapid micro-mixing and emulsification. Providing no blending displayed higher fluid loss when compared with blending at 2500 rpm using Hemilton beach blender for same DF with and without 1 wt% in-situ Fe(OH) 3 NPs, as shown in Table 4.8. Figure 4.13 shows that the mud cake collected following the filtration of unblended drilling fluid is full of precipitates, agglomerates and fish eyes as highlighted by the circles, while the one collected from a blended sample is much more smooth and does not show agglomerate. Very high mixing rates result in smaller particles in the mud as it serves formation of very small water pools, in the case of in-situ prepared NPs, and minimizing particle aggregation during the formation. Same effect was also observed during the addition of ex-situ prepared NPs. It was found by Altun and Serpen (2005) that variations in the mixing speed have important effects on fluid loss property and higher mixing speeds yielded lower filtration loss. In a similar study, Newman et al. (2010) showed that properties of drilling fluid were significantly affected when mechanical mixing is applied. It was also understood that to obtain smaller droplets of uniform size in water-in-oil emulsion, energy must be applied in the form of shear. Table 4.8: Effect of shearing effect on LTLP fluid loss control in the presence and absence of NPs. Samples Types Unblended DF (No NPs) LTLP Fluid Loss (ml/30 min) 2500 rpm Blending DF (No NPs) 2500 rpm Blending 1 wt% in-situ NPs +DF 90:10 (v/v) Oil: Water 8± ± ±0.2 84

101 Blended NP-based Mud cake Figure 4.13: Quality of unblended and blended mud cake Effect of presence of organophillic clays on fluid loss Table 4.9 shows the effect of varying the composition of organophillic clays from 12 to 15 kg/m 3 in the presence and absence of 1 wt% Fe(OH) 3 NPs. Table 4.9: Effect of organophillic clays on LTLP fluid loss control. Samples Types 90:10 (v/v) Oil: Water Amount of organophillic clays used in DF LTLP Fluid Loss (ml/30 min) DF without NPs DF+ with 1 wt% in-situ Fe(OH) 3 12 kg/m3 4.9± ± kg/m3 3.96± ±0.2 As evident from the table, increasing clays concentration improves loss prevention. It should be noted that clay content cannot be indefinitely increased. Solids content of the drilling fluid is one of factors that causes formation damage and decreases rate of penetration ROP (Newman et al., 2009). Solids are added to fulfill the functional tasks of the mud such as increasing mud density, viscosity and fluid loss control. The higher the amount of total solid in the drilling fluid the lower the rate of penetration, which in turn increases rig days and reduces productivity index. Unlike the Gilsonite LCM, 85

102 increasing the content of clays in presence of NPs increased fluid loss prevention, since more clays are available to form the mud cake. NPs would still be performing their role as bridging particles and will have higher surface to communicate with in the presence of more clays. A major outcome of the current study is that low NPs concentration can significantly reduce fluid loss. In events were high solid concentration is not desirable, for example due to the need to keep fluid density to a minimum, NPs can replace clay additive. Addition of low concentrations of NPs did not have any effect on the mud density, as will be detailed later Effect of Oil: Water ratio on fluid loss Filtration behavior of emulsified oil is strongly influenced by oil/water ratio, additive chemistry and concentration (Aston et al., 2002). Two formulations; namely 90:10 (v/v) and 80:20 (v/v) oil: water mixes, were tested in the presence and absence of in-house prepared NPs. This experiment is particularly relevant to in-house prepared NPs, since aqueous precursors are added. The results shown in Table 4.10 reflect a decrease in filtrate volume in the presence of Gilsonite LCMs and Fe(OH) 3 NPs. Table 4.11 shows the same trend in presence of NPs and absence of LCMs. Increasing the water content from 10 to 20 percent by volume caused the fluid loss to decrease 26% and 25% for drilling fluid control samples and drilling fluid containing Gilsonite LCM, respectively. Addition of NPs, again, decreases the fluid loss to 44% and 10% for ex-situ and in-situ method, respectively, due to the changed water content from 10 to 20 percent by volume. The reduction of fluid loss was dramatic in the case of ex-situ prepared NPs. This may suggest that extra water pools were originally needed to disperse better the particles. In-situ prepared NPs are more readily dispersed in the 10 percent water content. Therefore, in 20 percent water content, the fluid loss reduction was not varied too much. Higher water content may increase collision among water pools, which, in turn, may lead to more particle agglomeration (Husein and Nassar, 2010). This, in a way, decreases the effectiveness of the NPs. Nevertheless, one should not ignore the lower interaction between the organophilic clays constituting 86

103 the filter cake and the drilling fluid as the water content increases. Filtration rates through hydrophobic membranes results in much lower permeate flux (Deriszadeh et al., 2010). Aston et al. (2002) found the similar trends and proposed major savings can be attained by decreasing the oil to water ratio, while attaining more loss prevention. Table 4.10: Effect of Oil: Water ratio on Fluid loss control in presence and absence of LCM and in-house prepared Fe(OH) 3 NPs. Samples Types 90:10 (v/v) Oil: Water 80:20 (v/v) Oil: Water LTLP Fluid Loss (ml) Time DF DF+ LCM DF+LCM+ 1 wt% DF+LCM+ 1 wt% (min) ex-situ NPs in-situ NPs ± ± ± ± ± ± ± ± ± ± ± ± ±0.1 Table 4.11: Effect of Oil: Water ratio on fluid loss control in presence and absence of in-house prepared NPs. No LCMs added. Samples Types Time (min) DF LTLP Fluid Loss (ml) DF with 1 wt% ex-situ NPs DF with 1 wt% in-situ NPs 90:10 (v/v) Oil: Water 80:20 (v/v) Oil: Water ± ± ± ± ± ± ± ± ± Rheology behavior of NP-based fluid Drilling fluid with good pumpability exhibit lower viscosity at high shear rate and higher viscosity at lower shear rate. This property of drilling mud is used widely where high viscosities are required during tripping operation and low viscosities during drilling operation to clean the cuttings from the bottom of the hole (Chenevert and Sharma, 2009; Fraser et al., 2003). The plot of apparent viscosity and shear rate as shown in Figure 4.14 resembles the non-linearity of the curves at low shear rates and approach 87

104 linearity at high shear rates. The fact that addition of NPs created a slight change in the rheology supports the theory that NPs behavior is governed by NPs grain boundary and surface area/unit mass (Amanullah et al., 2011; Srivatsa, 2010). Although the addition of small concentration of NPs is not sufficient to cause a significant rheology changes in the system compared to the drilling fluid and drilling fluid with LCM only, particle size, nature of particle surface, surfactants, ph value and particle interaction forces may play significant role in altering the viscosity (Agarwal et al.,2009). The minor effect of NPs on viscosity is attributed to the low concentrations employed in this study. Abu Tarboush and Husein (2012) noted that NPs may increase the viscosity of heavy oil by bridging between asphaltene molecules and aggregates. The results are also highly dependent on the hydroxyl group (OH - ) on the surface of the NPs may lead to NPs agglomeration in an organic solution leading to a higher mass of selective physisorption of organic clay suspension on the NP-free surface, which may reduce the fluid viscosity slightly (Srivatsa, 2010). A small amount of NPs exhibit stable rheological properties. Fluid with high viscosity may cause excessive pumping pressure and decrease rate of drilling. Therefore, it is an important issue to design a suitable fluid rheology. Lee et al. (2009), who investigated the application of NPs for maintaining viscosity of drilling fluids at high temperature and high pressure, reported that the rheological behavior may depend on the particle type, size, concentration and inter-particle distance of NPs within the fluid. It was also reported that adding very small amount of mixed metal oxide did not change fluid rheological properties. It was shown that with an increase in temperature, the viscosity of drilling fluid containing 0.05 wt% cobalt NPs unchanged at 100 cp and remained stable. Therefore, potential application of NPs is to use them to stabilize in water-in-oil emulsion where NPs (solid/semi solid) dispersed in clays and electrolyte (NaCl salt) produced during the NP-based fluid formulation also work as a bridging material between the platelets of organophillic clays to form gel structure. The rheological properties of the in-house NP-based drilling fluid thus could suitably fulfill the drilling requirements. The comparison of the gel strength behavior of the drilling fluid, drilling fluid with LCM, drilling fluid with LCM and NPs together and NPs only are shown in 88

105 Figure The gel strength property of the NP-based drilling fluid compared to the progressive type gel strength of DF and DF+LCM also demonstrates superior functional behavior of NP-based drilling fluid. Similar observation was reported by Amanullah et al. (2011). Very high gel strength values are practically undesirable because they retard the separation of drilled cuttings at the surface and also raise the pressure required to re-establish circulation after changing bits. Furthermore, when pulling pipe, high gel strength may reduce the pressure of the mud column nearby the bit. If the reduction in pressure exceeds the differential pressure between the mud and the formation fluids, the fluid will enter the hole and cause a blow-out (ASTM, 2005; Amanullah et al., 2011; Chilingarian and Vorabutr, 1983). a) b) Figure 4.14: Rheological behavior of drilling fluid containing a) LCM together with inhouse prepared 1 wt% Fe(OH) 3 NPs, b) 1 wt% Fe(OH) 3 NPs no LCMs. From Figure 4.16 and Figure 4.17 we observe the time dependent rheological and gel strength behavior of the drilling fluid. The measurement was done immediately after the preparation and also after 1 month. After 4 weeks the fluid was found compliant with all specification for re-use. Analyses of the rheological profiles of the drilling fluids shown in Figure 4.16 indicate no significant changes of the viscous profile 89

106 of the NP-based fluid. The NP-based fluid immediately after preparation and static aging after 1 month demonstrate that the short as well as long term stability exist in the NPbased fluid. The 10 seconds and 10 minutes gel strength shown in Figure 4.17 also demonstrate the short and long term stability of the NP-based fluid to fulfill its functional task during drilling operation. 90

107 lb /100 ft² a) b) Gel Strenth (10 sec) Gel Strenth (10 min) DF DF+In-situ NPs DF+Exsitu NPs Figure 4.15: Gel strength behavior of drilling fluid a) with LCM and NPs together ex-situ and in-situ method b) in the absence of LCM,with NPs only ex-situ and in-situ method. 91

108 Figure 4.16: Shelf life of drilling fluid samples in terms of rheology behavior. Figure 4.17: Aging effect of drilling fluid samples in terms of gel strength behavior. 92

109 4.2.9 Drilling fluid density and ph Mud density is one of the important drilling fluid properties, because it balances and controls formation pressure and wellbore stability (Chilingarian and Vorabutr, 1983). A mud density of 0.93 g/cm 3 of the 90:10 (V/V) oil/water invert emulsion was found to be constant for all samples with and without NPs as shown in Table The addition of NPs did not increase the mud weight given the fact that their concentration was low and also due to the electrochemical behavior of NPs with clays. As discussed above, this is advantageous since it is one way of improving fluid filtration properties while maitaining the same mud density. Similar advantage of NPs was exploited to increase mud density while maintaining low mud visocistiy. A ph level of 12.5 was also found in all samples as also shown in Table 4.12, even with NPs addition. It should be noted with the fact that NaOH was added at the stoichiometric amount and NaCl was the reaction by-product, no changes in the ph of the aqueous pools is expected. Generally, changes in the ph of the water pools of invert emulsions could lead to unstability of the colloidal system by neutralizing charged surfaces at the water/oil interface or particles. Table 4.12: Density and ph values of drilling fluid in the presence and absence of LCM and in-house prepared Fe(OH) 3 NPs. Samples Types 90:10 (v/v) Oil: Water Properties Density (g/cm 3 ) Test samples DF DF +LCM DF+LCM with 1 wt% ex-situ NPs DF+LCM with 1 wt% in-situ NPs 0.93± ± ± ±0.02 ph Drilling fluid lubricity Even if a drilling fluid successfully meets all of the requirements, there is no guarantee that the rate of penetration will be acceptable, since poor lubricity and high friction and drag increase pipe sticking and drilling cycle (Amanullah et al., 2011). It needs to overcome frictional forces which is very much encountered during all stages of well 93

110 construction; including drilling, completion and maintenance. Friction originates from the rotation and/or sliding of a pipe inside the well in contact with either the wellbore (metalto-rock) or the casing (metal-to-metal). These forces hinder directional and extended reach drilling by creating excessive torque and drag (Amanullah et al., 2011; Hoskins, 2010). Excessive torque and drag in highly directional and extended-reach wells can exceed the mechanical limits of the drilling equipment, which may expedite wear and tear of down hole tools and equipment and thereby limit production. These problems can be minimized by using drilling fluid with high capabilities of lubricating the different components. In fact, the switch from water-based to oil-based or invert emulsion muds, despite the increase in cost, was originally proposed to help improving lubricity (Kercheville et al.,1986).friction dissipates energy and causes wear resulting in damage to the equipment. The way to ensure that frictional effects are minimized is through proper lubrication. In carrying out this function, lubricants create a lubricant film on surfaces of moving parts. The effect of the in-house prepared NPs on the lubricity of the invert emulsion drilling fluid considered in this study was measured by evaluating the coefficient of friction, as detailed in the experimental work. The hypothesis was that under the conditions of load and temperature resulting from the contacting surfaces, these NPs may furnish a thin film of lubricant layer on the contacting surfaces leading to reduced friction between the surfaces. These NPs may act as nano-bearings and contribute increasing the lubricity. Table 4.13 displays values for the coefficient of friction (CoF) and the accompanying reduction in torque and drag in the presence of 1 wt% in-house prepared Fe(OH) 3 NPs. Table 4.13: Co-efficient of friction (CoF) of drilling mud samples. Coefficient of friction % torque reduction NPs and DF without NPs DF with ex- DF with in- DF with ex- DF with in- conc. used (control) situ NPs situ NPs situ NPs situ NPs Fe(OH) 3 (1 wt%) 0.095± ± ± % 58.94% 94

111 It appears that in-situ prepared NPs disperse better and communicate better with the mother drilling fluid as opposed to the ex-situ prepared ones. Therefore, in-situ prepared NPs may carry a proportion of the load benefiting the improvement of antiwear property more than NPs prepared ex-situ. Thus using tailormade NPs in drilling fluid can reduce coefficient of friction and substantially increase lubricity. Improvement in lubricity reduces energy consumption, which, in turn, increases profitability. Oil-based drilling fluids have the inherent advantage of significantly lower coefficients of friction (CoF). The typical CoF for an oil-based drilling fluid is 0.10 or less (metal to metal) (Chang et al., 2011). In comparison, water has a CoF of 0.34 and the CoF of water-base drilling fluids typically ranges between 0.2 and 0.5 (Chang et al., 2011). Comparing between the typical oil based mud and NP-containing mud the friction mechanism is most likely a transfer of NPs to the counterface. This suggests that NPs in the contact zone act like ball bearings in the interface between the two surfaces. The small size allows the particles to penetrate into the surface and van der Waals forces ensure that the particles adhere to the surfaces. Regular lubricants, or oil as continuous phase, in drilling fluid can only form a single oil film (Kostic, 2010; Mosleh et al., 2009; Malshe et al., 2008), whereas NPs in drilling fluid can create an additional ball bearings action leading to better lubrication effect. Nonetheless, iron oxide/hydroxide nanoparticles act as a lubricious material (Reed, 2008). Sodium salts, e.g. NaCl salt formed as a by-product during the Fe(OH) 3 NP-based fluid formulation, may act as a lubricant as per some literature (Scoggins and Ke, 2011; Ke and Foxenberg, 2010). Table 4.14 shows that these side products, in fact, slightly increase the coefficient of friction. Therefore, the increase in lubricity observed when iron-based NP-drilling fluids are used can entirely be attributed to the nanoparticles only. 95

112 Table 4.14: Coefficient of friction (CoF) and % torque reduction in the presence and absence of 1 wt% NaCl salt in the invert emulsion drilling fluid. Salt and conc. Coefficient of friction DF without salt DF with salt % torque reduction (control sample) NaCl (1 wt%) ± ± % Nanosized particles are much more readily dispersible than micron-sized ones (Canter, 2009). When dispersed in a drilling fluid, minimum agglomeration and settling occur and a stable suspension form. The stable dispersion is also supported by the presence of surfactant molecules. Both in-situ and ex-situ prepared NPs are so small in size that a stable colloidal dispersion in drilling fluids can be achieved, which probably avoid the undesired precipitation caused by gravitation. With the formation of a stable wellproportioned dispersion through proper method, NPs are more prone to be trapped in the rubbing surfaces due to its excessive surface energy. Besides, dispersed NPs are deposited on the friction surface, trapped NPs at the interface and finally roughness of the surface is reduced by its polishing effect (Wu et al., 2007; Mosleh et al., 2009). Moreover, as the NPs tend to disperse uniformly, a more uniform contact stress between the contacting surfaces may result (Chang and Friedrich, 2010). Moshkovith et al. (2007) studied the lubricity properties of IF-WS 2 and reported that dispersion impacts the lubricity performance as the dispersed NPs possess solid lubrication properties due to its stability. It was also found that the aggregate size of the NPs depend on the mixing time. The in-house prepared NPs in this work can be engineered to have specific size ranges so that they can find their way into intricate spaces and maintain lamellar structure. It is, therefore, speculated that the coefficient of friction reduction is due to the surface boundary films provided by NPs that slide easily over one another like ball bearings. Similar findings have been reported in the literature on the effect of dispersing carbon and metallic-based NPs on tribological performance of lubricating oils (Zhang et al., 2009; Abdullah, 2008; Malshe et al., 2008; Verma et al., 2008). Specifically, a reduction in the coefficient of friction by over 25 percent was observed when adding nickel-based NPs to lubricants (Kostic, 2010). 96

113 In addition to reducing torque, higher lubricity also lowers the incidence of stuck pipe, which can significantly lower drilling efficiency. Estimates by exploration companies showed that stuck pipe while drilling costs more than $250 million each year (Q Max Technical Bulletin #7). Minimizing friction and the ability to transfer the weight to the bit are very important factors in drilling highly deviated extended reach and horizontal wells. Moreover, reduction in torque in the presence of NPs imply higher extended reach wells at a given torque and load on bit. From the aforementioned discussion it can be concluded that the ability of NPs to increase lubricity depends on the following features: 1. NPs can adsorb physically on any metal surface due to van der Waals forces. 2. The size of the NPs is so small that they can easily enter a macroscopic sliding contact. 3. The lubrication effect can be generated by the chemical nature of surfactant as described by Yang et al. (2012) and NPs altogether or NPs alone. Dispersed nanoparticles can help in reducing the agglomeration at the interface and improving the co-efficient of friction. The role of surfactant molecules is to improve the dispersion quality and stability of the NPs, since the level of improvement is measured relative to a control sample that contains the same amount of surfactant. 4. Coefficient of friction significantly reduced by NPs alone and the by-product salt did not have a significant impact on lubricity Preparation and performance evaluation of Fe(OH) 3 NPs in invert emulsion drilling fluids provided by different suppliers Three invert emulsion muds were obtained from three different suppliers having same oil:water ratio (90:10 v/v). These drilling fluids mainly differ in terms of the amount of organophillic clays and nature of emulsifiers. It is important to note that the nature of drilling fluids emulsifiers was not studied separately in this current study. The in-house in-situ and ex-situ NPs preparation techniques were employed to form Fe(OH) 3 NPs and the performance of the NP-based drilling fluids was evaluated. For a drilling fluid; 97

114 filtration, rheology, density, ph need to be suitable to fulfill the drilling requirements. The results in Table 4.15 compare the density, ph and the API LTLP fluid loss at 30 min for samples with and without Fe(OH) 3 NPs. The density and the ph of the samples remained constant, while fluid loss was decreased significantly. Moreover, the in-situ prepared NPs displayed better performance and reduced fluid loss to a higher extent. This fact can be attributed to better dispersion and communication with the rest of the drilling fluid constituents, as discussed earlier. Table 4.15: Effect of ex situ and in situ prepared Fe(OH) 3 NPs on the performance of three different invert emulsion samples of drilling fluids provided by three different suppliers. Concentration of NPs 1 wt%, composition of invert emulsion: (90:10) oil:water (v/v). Supplier A Samples Density ph API LPLT fluid loss (g/ml) (ml/30 min) DF 0.93± ±0.2 DF+LCM 0.93± ±0.1 DF+LCM+Ex situ NPs 0.93± ±0.1 DF+LCM+In situ NPs 0.93± ±0.2 Supplier B DF 0.93± ±0.3 DF+LCM 0.93± ±0.4 DF+LCM+Ex situ NPs 0.93± ±0.2 DF+LCM+In situ NPs 0.93± ±0.1 Supplier C DF 0.90± ±0.2 DF+LCM 0.90± ±0.1 DF+LCM+Ex situ NPs 0.90± ±0.1 DF+LCM+In situ NPs 0.90± ±0.1 NPs were found to be suitable for use in drilling fluids due to its functional characteristic of maintaining low viscosity and expected to minimize the drilling problems. In-situ control of viscosity of drilling fluids in deep well bores is currently 98

115 Apparent viscosity (cp) at 600 rpm limited (Lee et al., 2009). During operation, and as drill cuts suspend into the drilling fluid, viscosity increases and alters the rheology in the subterranean wells (Adekomaya and Olafuyi 2011; Herzhaft et al., 2006). Therefore, a gradual tuning of the rhelogical properties of the drilling fluids is required to maintain good performance. As noticed from a previous experiment, NPs, especially in-situ prepared ones, generally reduce the viscosity of drilling fluids due to their electrochemical behavior with clays. The decreased in viscosity with the addition of NPs may provide the in-situ tunability/controllability of the fluid viscosity during drilling in subterranean wells. The rheological properties of the drilling fluids obtained from different suppliers were evaluated in the presence and absence of the in-house prepared NPs. Apparent viscosities at 600 rpm were plotted for comparison in Figure The results show consistent decrease in the apparent viscosity in the presence of in-house prepared NPs. This also confirms the fact that in-situ prepared NPs better interact with the drilling fluid displaying more reduction in the apparent viscosity. Similar observation was reported by Abdo and Haneef (2010) when using Montmorillonite NPs compare with regular commercial bentonite particles. Figure 4.18: Apparent viscosity at 600 rpm of 3 invert emulsion drilling fluids provided by different supplies in the presence and absence of 1 wt% Fe(OH) 3 NPs. Composition of invert emulsion: (90:10) oil:water (v/v). 99

116 The data in Figure 4.18 suggest that in the presence of NPs lower the viscosity can reduce the pumping power requirement without compromising the carrying capacity of the drilling fluid to transport and drop off cuttings efficiently Performance of Fe(OH) 3 NPs in water based mud (WBM) Fluid invasion into porous formations can damage reservoirs and reduce productivity by blocking hydrocarbon exit flow paths or causing formation damage. Fluid penetration while drilling using WBM can lead to shale formation swelling and, subsequently, well bore instability (Sensoy et al, 2009). Currently most fluid loss additives in WBMs have formulations based on bentonite clays, lignite, asphaltite and organic polymers (Kosynkin et al., 2011; Moore et al., 1974). In terms of environmental and economical considerations, WBM would be preferred if the interaction between the fluid and the shale could be controlled. Water based muds are suitable only for relatively low temperature and pressure drilling operation (Agarwal et al., 2009). Xanthan gum is a rheological modifier that typically used in WBM to increase viscosity and improve dispersion stability. In the current experiment, few mg of surfactants (Dioctyl sodium sulfosuccinate) were used to provide adequate stability of NPs. Table 4.16 displays fluid loss results after 30 minutes for WBM containing 0.60 wt% Fe(OH) 3 NPs formed ex-situ and in-situ methods. Table 4.16: API LTLP WBM fluid loss at 30 min in the presence and absence of 0.60 wt% in-house prepared Fe(OH) 3 NPs. Water based DF+ exsitu NPs situ NPs Water based DF+ in- Water based DF 8.8± ±0.2 (9%*) 6.3±0.2 (28.4%*) *Fluid loss reduction, %. Comparison of the fluid loss behavior of invert emulsion and water based fluids shows that emulsion fluids exhibited a better fluid loss control. The types of clays used in both muds were different. Organophillic clays (surface modified bentonite clays) which are normally treated with amines in order to make them oil dispersible and largely used in invert emulsion mud formulation, whereas regular unmodified bentonite clays are used 100

117 in water based mud. Due to surface modification, organophillic clays extended the clay properties in terms of rheology, carrying capacity, fluid loss control, etc. (Paiva et al.,2008; Juppe et al.,2003). Comparing the results for WBM alone to the samples containing the NPs it can be concluded that the NPs probably contributed to the mud cake and resulted in an overall reduction in fluid loss. It can also be inferred that the in-situ prepared NPs interacted better with the mud cake, again, probably as a result of better dispersion in the original mud. Cei et al. (2011) used commercial and non-modified silica NPs with sizes ranging from 5 nm to 22 nm in a WBM and showed that concentrations 10 wt% NPs reduced fluid loss by 25-30%. Similarly Kosynkin et al. (2011) showed that using graphene oxide (GO), a combination of large flake GO and powdered GO in a 3:1 ratio to perform, in WBM with a concentration of 0.2% (w/w) based on carbon content resulted in 15.3% fluid loss reduction. Amanullah et al. (2011) used 0.14% (w/w) silica NPs in WBM formulation along with different additives including polymeric additives. Their study showed that the API fluid loss behavior of nano-based fluid showed similar fluid loss as the original water based mud and did not improve the fluid loss reduction performance. It was observed by Flask and Jamison et al. (1989) that fluid penetration into the pore space was controlled by the size of the aggregates in the drilling fluid relative to the pore size of the formation. The size of aggregates in the drilling fluid controlled initial bridging and formation of the filter cake. There are few guidelines used in oil and gas industry to choose particle size in order to optimize their role as bridging materials. Among the guidelines, Suri and Sharma (2004) showed that in order to form bridges, particle sizes should not be larger than one third of the pore throat size. This implies that wide range of NPs used in the current work makes it more effective in plugging nano to micro pore throat. Of course, NPs plugged primarily the ones that fit that size and then in some cases aggregate together to plug the big pore size. Similar observation was reported by Sensoy et al. (2009). Overall, WBM loss reduction contributes to reducing wellbore instability problems. 101

118 Toxicity evaluation Fe(OH) 3 samples In recent years, the usage of inorganic NPs has increased exponentially for a variety of applications (Buzea et al., 2007). In this context, it is necessary to assess the environmental and biological risks of NPs used in this work. It should be noted, nevertheless, one of the advantages of the in-house methods developed in this work is the fact that the resultant NPs is contained within a liquid mixture rather than being airborne. This minimizes inhalation and reduces health risk significantly. In Alberta, onsite disposal of the drilling waste is allowed, provided that criteria imposed by the Alberta Energy and Utilities Board (AEUB) are met (AEUB, G50, 1996). To be rated essentially non-toxic, an EC 50 of at least 75% of the original waste concentration must be obtained. This threshold limit is compatible with pass/fail results in bioassay. It is therefore useful to have an estimate of the ferric hydroxide NPs concentration that could cause bioassay failure, i.e EC 50 (15 min)< 75% (Ashworh and Walker,2006). Iron hydroxide NPs were broadly used and selected for their low toxicity. Commercial Fe 3 O 4 NPs exhibited toxicity at 45% of initial concentration (García et al., 2010). Iron hydroxide NPs prepared in this work only showed toxicity when NPs concentration increased to concentrations > 15 % by volume, as per Table Therefore, it is safe to say that at the concentrations employed in this work, 1 wt%, Fe(OH) 3 NPs is nontoxic. Table 4.17: Microtox bioassay of Fe(OH) 3 NPs. Test Fe(OH) 3 Concentration (V/V) Results Interpretation (AEUB,G-50) Pass/Fail; (Pass if EC 50 >75%) EC 50 50% 18.7 Fail EC 50 35% 22.5 Fail EC 50 35% 37.5 Fail EC 50 20% 64.8 Fail EC 50 15% 100 Pass 102

119 4.3 CaCO 3 Nanoparticles (NPs) Characterization As described in Section 3.2 of the experimental work, two methods were adopted to form CaCO 3 NPs; namely ex-situ and in-situ. Moreover, in-situ CaCO 3 was prepared from salt precursors as well as CO 2 injection X-ray diffraction analysis The structure prepared by precipitating CaCO 3 NPs ex-situ starting from aqueous Ca(NO 3 ) 2 and Na 2 CO3 precursors is shown in the X-ray diffraction (XRD) patterns of Figure The X-ray diffraction pattern shows that there is evidence of distinct peaks which would be expected from a crystalline material. Calcium carbonate has three crystal structures; calcite, aragonite and vaterite (Kabalah-Amitai et al., 2013). Typically, calcium carbonate exists as calcite, which is the most thermodynamically stable structure at ambient temperatures and pressures (Lee et al., 2001), whereas vaterite is most unstable. Aragonite is less stable than calcite and commonly found in marine organisms (Tai and Chen, 2008). The data obtained from the X-ray diffraction patterns in Figure 4.19 demonstrates the crystalline nature of the sample under analysis. The X-ray diffraction pattern of the synthesized calcium carbonate exhibits characteristics peaks at 2θ values of These are the strongest peaks observed in the X-ray diffraction patterns of the analysed samples which represent calcite (CaCO 3 ). Knowles and Freeman (2004) and later Jamaluddin and Ahmad,(2010) stated that CaCO 3 crystals overlapping each other induced the fibrous morphology of the crystal, thus creating rough glaze surface. Due to its fiborous nature, calcite can cement the existing rock grains or fill the fracture and act as a bridging agent. All the precursors were assumed to react completely to form calcium carbonate. This observation is agreeable with previous studies (Yao et al., 2010; Rahman and Oomeri, 2009; Tong et al., 2004). 103

120 Figure 4.19: X-ray diffraction pattern of ex-situ prepared CaCO 3 NPs starting from the aqueous precursor salts Size distribution of ex-situ prepared CaCO 3 The TEM photographs and the corresponding particle size distribution histogram for the ex-situ prepared CaCO 3 are shown in Figures 4.20 and The histogram shows a wide size distribution with most of the population falling in the range between nm and a mean particle size of 60 nm. Figure 4.20b demonstrates a high degree of NPs crystalline nature of the sample taken from an illuminated area of crystals are known to form easily under laboratory conditions, especially when calcium carbonate precipitates quickly (Lee et al. 2001). It can be assumed that Ca 2+ ion concentration on the surfaces of nanoparticles resulting in the growth of CaCO 3 crystals as shown in Figure 4.20a. The TEM image shows that the ex-situ prepared NPs have different shapes, from subrounded to subangular. The picture clearly shows that there is crystalline particles overlapping and affinity towards formation of polycrystalline. The images were consistent with the D spectra which showed the crystal structure of CaCO 3 NPs. During NPs preparation, higher collisions rate of NPs might increase the probability of 104

121 Number of Particles, % the formation of larger particles and aggregation of fine particles (Nassar and Husein, 2007a), especially since no capping agents were used to prevent aggregation and shearing was the only way to control particle size. a) b) Figure 4.20 : TEM photographs of ex-situ CaCO 3 NPs at two different magnifications. Figure 4.21 : Particle size distributions of ex-situ prepared CaCO 3 NPs. 105

122 4.3.3 Determination of particle size of in-situ prepared CaCO 3 Calcium carbonate NPs are considered ideal bridging materials of the pore throats of the mud cake. The particle sizes in nano domain might generate slurries and suspensions in drilling fluid that will show a reduced tendency to sediment or sag and minimize the differential sticking problems (Ballard and Massam,2009). TEM results show that the ex-situ prepared CaCO 3 NPs are bigger than their Fe(OH) 3 counterparts. SEM images of the mud cake without and with in-situ prepared CaCO 3 NPs are shown in Figure It should be noted that WBM was used this time due to limitations associated with EM imaging of oil-based mud cake, especially gold coating, which took much longer time. As discussed earlier, SEM imaging of the filter cake was the only way of evaluating in-situ prepared NPs. One thing to note at this stage of discussion, there is no smooth surface like the one obtained with in-situ Fe(OH) 3 NPs formulated in invert emulsion mud. This fact is reflective of the overall poor fluid loss prevention when the two cases are compared. The mud cakes surface roughness was varied from cake to cake and particle sizes varied as well. Texture changes could also happen during evaporation of water and gold coating of the surface of water based mud cakes (Chenevert, 1991). Mud cake without NPs was rough and the surface was composed of chunks of large mud particles, which explains the poor loss prevention capability of the mud cake. In the presence of in-situ NPs prepared from aqueous precursors as per reaction (R2), the surface became smoother, although roughness is still apparent. Nevertheless, particles were much smaller in size and could tighten up fluid intrusion through the surface. Similarly mud cake with in-situ NPs prepared by bubbling CO 2 as per reaction (R5) surfaces was even smoother than the in-situ NPs prepared per reaction (R2). Comparing the results of with and without NPs clearly demonstrates that CaCO 3 NPs are effective in forming bridges. Clay surfaces were covered with CaCO 3 particles in both NP-based mud cake, as was evident from the white color of the cake surface. The observed morphologies of the samples showed distinct features in terms of particle sizes and as well as surface composition evaluated by EDX of Figure

123 a) b) 100 nm c) d) 100 nm e) f) 100 nm Figure 4.22 : SEM images of mud cake a&b) without NPs ;c&d) in-situ CaCO 3 NPs (R2); and e&f) in-situ CaCO 3 NPs (R5). 107

124 From the SEM images it is evident that the pore openings in the mud cake without NPs were filled with NPs leading to reduced fluid loss, as will be discussed in the following section. EDX spectra of Figure 4.23 provide elemental composition of the surface of the mud cakes as shown in Figure Magnification of mud cakes showing the grain sizes and particles size distributions were estimated by using ImageJ software as shown in Figures 4.24 and The SEM images of mud cake without NPs revealed that the grains mostly irregular from subrounded to subangular (Figure 4.22a). It is also noted that the pore opening sizes range from 4 nm to 180 nm with average pore openings were located in nm range. These pore openings are resembled as a pore throat in shale formation. The EDX analysis revealed that Ca content in mud cake without NPs was below the detection limit or trace amount of Ca content was present (Figure 4.23a). The in-situ NPs formation was confirmed by the presence of Ca content and increased amount of Ca element, as per EDX images of Figure 4.23b-c. Figure 4.25 shows the particle size distribution of in-situ prepared CaCO 3 NPs used as fluid loss additive (bridging agent) in our experiment. The NPs particle size distribution (1-200 nm range) were confirmed by the SEM images and reported only those were on the surface of the cake. More than 50% of NPs were 1-30 nm range as shown in Figure 4.25 and potential to plug the nanometer sized pore openings of the mud cake as shown in Figure A wide particle size distribution was available that covered some large particles available to bridge across large openings or fracture. However, it is also to be noted that some NPs might diffuse into the cavity of the pores permanently and were not counted in the measurements. A magnified photograph of NPs indicated that particles entangled together to form aggregates and deposited on the clay pores to form a low permeability mud cake as shown in Figure 4.22c-f. 108

125 a) b) c) Figure 4.23 : Elements containing mud cake a) without NPs,b) with insitu NPs (R2) and c) with insitu NPs (R5) from EDX data. 109

126 Frequency,% Pore openinigs in mud cake (nm) Figure 4.24 : Available pore openings (nm) in mud cake of DF without NPs. Figure 4.25: Particle size distribution of in-situ CaCO 3 NPs, prepared by reactions (R2) and (R5), in the mud cake. 110

127 The range of NPs size is narrow and it can be seen that the method followed is an appropriate method for NPs production. The selection of CaCO 3 NPs as bridging material with a specific particle size distribution was in accordance with the physicalchemical characteristics of formations to be drilled. It is important to have a substantial colloidal fraction of particles in the mud with a broad PSD (particle size distribution). The criterion of selection of particle size of bridging agent is particles about one-seventh to one-third the size of the maximum pore throat and the fluid must maintain a significant concentration of those particles throughout the interval (Cargnel and Luzardo,1999). Thus, if NPs, for example, is larger than the diameter of the pores, it will simply sit on top of that pore. There are other various guidelines used in industry to choose the particle size of bridging materials that can form an efficient external filter cake. A median particle size of the bridging agent equal or slightly greater than one third of the median pore size of formation and concentration of bridging agents must be at least 5% by volume in final mud mix (Abrams,1977), 90% of the particles are smaller than or equal to the pore size of the rock ( Hands et al.1998). In the mud cake pore throat size diameter falls below 10% at nm range and 90% of nanoparticles lies between 1-60 nm range. According to the relationship stated above, the NPs size is more suitable for bridging materials at the cake surface and ensure that tailor made NPs are potential to reduce the permeability of mud cake. As the dimension of NPs lies in the contiguous area between the clusters and the macroscopic materials, they will not directly dictate macroscopic properties, but bring their own unique effects such as surface effect, size effect etc (Nabhani et al.2011). Mud cake contains interconnecting pore spaces more like those of permeable rock considered as a theoretical pore throat diameter of shale and is just an approximation. A mud having wide range of particle size distribution adsorbed by clay might slow down the filtrate. It presumably would seal the surface pores, stuck on the surface of the clay and filter paper and establish the formation of low permeability filter cake, whereas without NPs mud containing only clay start to form highly permeability filter cake. The correct particle size distribution provides better compaction medium with constrained flow of liquid from the drilling fluid. Therefore, drilling fluid containing CaCO 3 111

128 NPs of sizes ranging up to 200 nm, the requisite maximum were able to effectively bridge the formation and formed filter cake. The relative pore size openings of the mud cake of drilling fluid without NPs explained that the SEM result was found to be in good agreement with NPs considered as a bridging or plugging agent to reduce the fluid loss LTLP Filtration of in-house prepared CaCO 3 NPs Drilling muds can cause large irreversible damage to fractures and dramatically reduce the productivity of wells. Leoppke et al. (1990) found that if the particle size is not compatible with the fracture width, a stable bridge cannot be formed and therefore tailored particle size distribution provides the best plugging capabilities. It is essential to drill the wells with minimum cost in loss of fluids. Al-Riyamy and Sharma (2004) used 5 wt% CaCO 3 of narrow size distribution and found that volume of the filtrate decreased when CaCO 3 was used and reduced the invasion of emulsion droplets into the formation, although granular CaCO 3 LCM were found much less effective (Jiao and Sharma, 1996). Currently all types of CaCO 3 are used largely as fluid loss control additives in drilling fluid. But the current size range of CaCO 3 used does not serve the purpose of the complete fluid loss control. More interestingly, the nanometer CaCO 3 could result in much thinner filter cakes than those obtained using large sized CaCO 3. Isambourg and Matri (1999) showed how much force required to free a stuck pipe with a change in mud cake thickness. This highlights the importance of nano drilling fluid with thin mud cake development. The first step when choosing the particle size distribution of bridging agent specifically CaCO 3 in drilling fluid is the petrophysical characterization and pore geometry determination of the rock. In consolidated sands, the criterion of selecting particle size as bridging agent is (Cargnel and Luzardo,1999) : 1/7 D Pore throat < D particle < 1/3 D Pore throat Bentonite clay particles have sizes of ~1-2 μm (at dispersed phase) according to the supplier. During the migration of particles through the paper filter (2.7 µm pore diameter) in our case resembling pore throats of the rock, they began to accumulate in 112

129 the filter surface. To avoid internal blocking, it is necessary to create a mud cake at the surface of the pore throat in wellbore. Static filter loss tests are relative, i.e, they can compare on a qualitative level which mud systems are preferable and widely used by drilling crews for routine field tests (Nyland et al., 1988). Total fluid loss is the indicator of the filtration controllability of mud and its additives. It is apparent from the Table 4.18 that more than 60% of the API fluid loss reduction occurred using ex-situ NPs and 55% when used in-situ CaCO 3 NPs prepared by reaction (R2). NPs primarily form a impermeable filter cake surface on the filter paper. Permeability decreases with increasing fraction of colloids and is affected strongly by particle size and shape of NPs. Flocculation causes particles to form a loose and open network leading to higher filtration rate as indicated by the drilling fluid without NPs where clays are dominant. After adding CaCO 3 NPs in the drilling fluid probably acted as a cementing and bridging agent that stabilized the bentonite clay aggregates and could decrease the clay swelling and prevented their disintegration. Due to CaCO 3 concentration in drilling fluid, which probably below the flocculation value caused the migration of dispersed NPs into the pores of mud cake during filtration. Comparison between Tables 4.18 and 4.19 shows that total filtrate is the highest for the water based mud than the invert emulsion based mud. In both cases, the invert emulsion NP-based mud had a very low filtration rate during the first 7.5 min and the rate still lower during the 30 min. The water based NPs mud had a much higher initial filtrate rate but after 30 min it was still closely two times greater than the invert emulsion NP-based mud. CaCO 3 in water based mud might have a flocculating effect seen by the relative fluid loss performance with respect to invert emulsion mud and also affected by the difference in mud constituents in the two fluid systems. Using 3 wt% nano CMC and nanopolymer as a fluid loss additives in water based mud, 14% and 19% respective fluid loss reduction was noticed in literatures (Saboori et al,2012; Manea et al.2012), whereas 3 wt% CaCO 3 NPs addition in the current experiments yielded 30% fluid loss reduction. 113

130 Table 4.18: API LTLP fluid loss comparing invert emulsion drilling fluid as base case with invert emulsion drilling fluid samples containing 4 wt% in-house prepared CaCO 3 NPs using reaction (R2). No LCMs added Samples Types Time (min) LTLP Fluid Loss (ml) DF DF + ex-situ NPs DF +in-situ NPs 90:10 (v/v) Oil: Water *Fluid loss reduction,% ± ± ± ± ±0.6 (68%*) 3.9±0.3 (55%*) Table 4.19: API LTLP fluid loss comparing water based drilling fluid as base case with water based drilling fluid samples containing 3 wt% in-house prepared CaCO 3 NPs by reaction (R2). Samples Types LTLP Fluid Loss (ml/30 min) DF DF + ex-situ NPs DF +in-situ NPs Water based DF 9.5± ±0.2 (32%*) 6.8±0.2 (28%*) *Fluid loss reduction,% When Ca(NO 3 ) 2 and Na 2 CO 3 precursors are added in the drilling fluid in order to form CaCO 3 NPs, a bi-product of NaNO 3 salt was also produced. This formation increased the ionic atmospheric charge on clay sheets. The attractive force between the ionic atmosphere might force the individual clay sheets to regrouping, decrease the pore openings and interlock at random angles, thereby fluid loss reduction would happen. Since, such regrouping is a matter of statistical probability, some clay sheets may still have openings difficult to move and, therefore, complete fluid loss reduction was not possible. On the other hand, sodium nitrate itself acts as nitrogen based fertilizer. Adding nitrates encourages the proliferation of nitrate-reducing bacteria in the oilseawater mixture. When present in the appropriate numbers these bacteria help loosen oil from the rocks containing the reservoir. For this reason, since long Statoil Norway is injecting sodium nitrate along with seawater to pump oil from the underground reservoir (RSC,2003). 114

131 A 4 wt% CaCO 3 NPs concentration represents the optimum concentration in which the volume of filtrate reached minimum values and better arrangement of particles occurred in the filter cake surface turning into an impermeable cake. Besides, the spurt losses are found lowest. Comparing between Tables 4.18 and 4.20, it can be easily seen that in-situ CaCO 3 NPs reaction (R5) yields lower spurt loss, filtration rates and total filtration volume. The cake formation was instantaneous and effective. During the initial stage of filter cake forming, NPs plug or bridge the near surface pores and reduces formation permeability. Bailey et al. (1999) showed that the particle bridging reduced the spurt loss. Because of this bridging tendency, quick external filter cake formation is obvious in case of the in-house prepared CaCO 3 NPs using reaction (R5). Table 4.20: API LTLP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing 4 wt% in-house prepared CaCO 3 NPs using reaction (R5). Samples Types Time (min) DF LTLP Fluid Loss (ml) DF +4 wt% in-situ NPs 90:10 (v/v) Oil: Water ± ± ± ±0.4 (66%*) *Fluid loss reduction,% NPs of CaCO 3 modify the structure of clay due to Ca 2+ cation exchange leading to agglomeration of clay particles, which also increases internal friction among the agglomerates and thereby reduced permeability of mud cake. As far as these NPs are considered as fluid loss reducing agent, it gains better properties of keeping the cumulative volume of filtrate at low values. It is due to the fact that when these NPs are brought into the clay particles, the interaction area was considerably increased due to higher surface area of NPs. Increased area to volume ratio in NPs cause the increase of ionic group molecular weights for adsorption on the clay particle surface and attached them to each other leading to form more colloidal particles. In addition, the presence of CaCO 3 NPs may induce a Brownian diffusion with clay particles. Spurt losses observed 115

132 with CaCO 3 are acceptable from a drilling point of view. Looking at the above tables, it is obvious that the effect of NPs presence intensified the flow resistance of the system HTHP Filtration of in-house prepared CaCO 3 NPs High temperature filtration rates could not be predicted from low temperature filtration. Filtration rates increased at high temperature that could be attributed to the reduced viscosity of oil alone. The samples exhibited a very low fluid loss at low temperatures and same relative performance at high temperatures. Nanos having an excellent thermal conductivity are expected to be the materials of choice in HTHP wells (Agarwal et al., 2009). When the pressure is applied (500 psi differential in the HPHT tests) the filtration became slow due to the bridging/agglomeration tendency of NPs at high temperature. The HTHP fluid loss property of CaCO 3 NP-based drilling fluid prepared through reaction (R2) is shown in Table It showed that NPs concentration equal to 4 wt% reduced more than 70% of the fluid loss. Similar trends were observed at previous Fe(OH) 3 NPs. The differences are thought to be a result of the surface morphologies of the two different NPs. In order to determine the HTHP fluid loss with CaCO 3 NPs prepared in reaction (R5), results are reflected in Table It is shown that NP-based mud provided the lowest spurt loss and total filtrate loss. Addition of optimum concentration of NPs improved filtration properties, however the extent of the improvement depend on the mud type, nature of NPs material, NPs synthesis method, size distribution of NPs and concentration of surfactants. As it can be seen, the total filtrate passes through is minimum in the case of in-situ CaCO 3 NPs prepared through reaction (R2). But more interestingly, fluid loss towards zero is apparent in reaction (R5). 116

133 Table 4.21: HTHP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing 4 wt% in-house prepared CaCO 3 NPs using reaction (R2). Samples Types Time (min) HTHP Fluid Loss (ml) DF DF+ ex-situ NPs DF+in-situ NPs 90:10 (v/v) Oil: Water ± ± ± ± ±0.1 (71%*) 5.4±0.2 (72%*) *Fluid loss reduction,% Table 4.22: HTHP fluid loss comparing invert emulsion drilling fluid as base cases with invert emulsion drilling fluid samples containing 4 wt% in-house prepared CaCO 3 NPs using reaction (R5). Samples Types Time (min) DF HTHP Fluid Loss (ml) DF +4 wt% in-situ NPs 90:10 (v/v) Oil: Water ± ±0.2 0 (100%*) *Fluid loss reduction,% High pressure and high temperature filtration tests clearly demonstrated that CaCO 3 NPs have the ability to reduce filtrate loss to the formation. No emulsion droplets were observed in the filtrate means emulsion droplets containing NPs were needed to form a stable external filter cake. The acid soluble CaCO 3 NPs could be concentrated at oil/water interface as like Fe(OH) 3 NPs and restricted the flow of fluid to the porous media Drilling fluid density and ph As different formations are encountered with depth increases, the densities of drilling fluids shall be proportionately adjusted to balance the drilling system while drilling. So weighting materials should be continuously added to drilling fluids. CaCO 3 NPs used as weighting materials in adjusting drilling fluid density could reduce the extra additive cost. 117

134 As shown in Table 4.23, a significant change in the drilling fluid density was seen. Due to its distinctive nature as weighting material, addition of CaCO 3 NPs can increase the fluid density. But no change in ph was observed. It can be observed that the ph is 12.5 remains constant even after addition of CaCO 3 NPs. This effect is probably explained by the absence of chemical interactions between CaCO 3 NPs with other materials used in drilling fluids. Apart from that the NPs concentration was too low to increase and/or decrease of density and ph of CaCO 3 NP-based invert emulsion fluid. NPs may be embedded in the clay matrix. Table 4.23 : Density and ph measurements of drilling fluid samples in the presence and absence of 4 wt% in-house prepared CaCO 3 NPs. Samples Types 90:10 (v/v) Oil: Water Properties Density (g/cm 3 ) DF Test samples DF+ 4 wt% exsitu NPs DF+ 4 wt% insitu NPs 0.89± ± ±0.02 ph Rheology behavior of NP-based fluid When rheological properties are considered, CaCO 3 NPs provide satisfactory mud system. Mud rheological properties (viscosity vs. shear rate) were measured at room temperature and pressure. Analyses of the rheological properties of the drilling fluids shown in Figure 4.27 indicated a viscous profile of the nano-based fluid at low shear rate, but at high shear rate there was no significant changes. Using CaCO 3 microparticles, the viscosity of drilling fluids were increased substantially as shown by Manea et al. (2012). Properties measured at 10-sec and 10-min gel strength were also shown in Figure

135 Apparent Viscosity (cp) 1000 DF DF+4wt% In-situ NPs (R2) DF+4wt% Ex-situ NPs(R2) DF+4wt% In-situ NPs(R5) Shear Rate (Sec -1 ) Figure 4.27: Rheological behavior of invert emulsion drilling in presence and absence of 4 wt% in-house prepared CaCO 3 NPs. No LCMs added. Figure 4.28: Gel strength behavior of invert emulsion drilling fluid in presence and absence of 4 wt% in-house prepared CaCO 3 NPs. No LCMs added. 119

136 All the muds had almost similar viscosities in the high shear range although NPbased muds were slightly thicker in the low shear range than conventional invert emulsion based muds (DF). The shear thinning properties of drilling fluid would be advantageous in providing better hole cleaning. Similar trends were observed by Simpson, (1979) and Sensory, (2010). With the addition of CaCO 3 NPs (both ex-situ and in-situ), the gel strength was also increased. Similar observations were also reported by Manea et al.(2012). CaCO 3 NPs as a bridging agent might have proper mechanical and chemical consistency to be used in NP-based drilling fluid design. Chemically, it is acid soluble so that CaCO 3 laden mud cake can be removed easily from the porous matrix to recover the permeability of the rock. On the basis of the results, we believe NPs size and ability to keep particles dispersed throughout the mud system allowing fluid loss reduction. CaCO 3 NPs based mud system proved versatile enough to provide better fluid loss control while retaining a consistent viscous profile Drilling fluid lubricity Lubricity is a very important parameter that was considered due to long extended reach characteristics of wells. Coefficient of friction less than 0.1 or less is generally advantageous as it helps the cuttings to travel as discrete particles over shaker screens (ASME, 2005). The choice of CaCO 3 NPs as a lubricity additive is due to its availability. With the help of surface activity of CaCO 3, NPs can effectively lower the friction between drilling tools and borehole walls and reduce the difficulty in drilling of highly deviated wells and horizontal wells. 4 wt% of CaCO 3 NPs induced appreciable reduction in the coefficient of friction. A comparative performance with regular base drilling fluid is shown in Table The friction of coefficient was reduced to 2.1% and 38% by using ex-situ and in-situ prepared CaCO 3 NPs, respectively. Using commercial silica as NPs in drilling fluids improved lubricity by 3-5% as reported by Riley et al. (2012). High drilling cost can be caused by slow drilling rates due to improper lubricity quality. Therefore the results indicated the feasibility of CaCO 3 NPs that could permit the improved drilling rate. 120

137 Table 4.24 : Coefficient of friction of invert emulsion drilling fluid in presence and absence of 4 wt% in-house prepared CaCO 3 NPs. No LCMs added. DF without NPs (control) Co-efficient of friction DF+ex-situ NPs DF+in-situ NPs % torque reduction DF+ex-situ NPs DF+in-situ NPs % 37.89% 4.4 Invert emulsion drilling fluid API fluid loss characterization using other NPs From a practical point of view, the presence of NPs in drilling fluid is worth to be studied, evaluated and therefore found promising. The advantages of using these NPs are that, there is formation of more continuous and integrated mud cake. Having low permeability and low porosity mud cake, there is less volume of filtrate entering into the formation and mud cake thickness is less compared to DF and DF with LCM cases. Regular mud systems contain large quantities of fine solids that penetrate the productive formation causing irreversible plugging and influence negatively in the productivity of the wells. Barite (BaSO 4 ) of drilling fluids is such a component and when it invades the productive area, it creates internal block within the formation which is difficult to remove (Cargnel and Luzardo,1999). In normal, barite in drilling fluid is used as weighting material. Conventional powdered barite exhibit an average particle diameter in the range of microns. To adequately suspend these materials requires the addition of gellant such as bentonite. However more gellants addition could increase fluid viscosity and undesirable fluid properties (Ballard and Massam, 2009). The nano barite could alleviate those problems in drilling fluid and may control colloidal interaction of particles. Different NPs are prepared in the novel method described in the experimental section to validate the prepared method. The techniques provide novel insight in fluid loss reduction problems while drilling wells and help in counting the problems in a more efficient and environment friendly manner. BaSO 4 and FeS NPs were tested to check their specific performance in fluid loss control as shown in Table Addition of 3 wt% NPs in drilling fluid reduced fluid loss from 68 to 85 % for BaSO 4 and 90% for FeS NPs. The adsorption process in clay involves a negative global charge in its surface, is 121

138 generally balanced by inorganic cations (Ba 2+, Fe 2+ ) in the internal and external surfaces of clay material. Some nanoparticles may also aggregate and deposit into the cake, therefore the Brownian motion of the particles and the van der Waals and repulsive forces for the nanoparticles are equally important. Table 4.25 : API LTLP fluid loss of invert emulsion DF in presence and absence of 3 wt% in-house BaSO 4 and FeS NPs. No LCMs added. DF DF+ ex situ BaSO 4 DF+ in-situ BaSO 4 ml/ 30 min *Fluid loss reduction,% 10.95± ±0.3 (68%*) 1.6±0.3 (85.3%*) DF+ ex-situ FeS DF+ in-situ FeS 1.15±0.3 (89.5%*) 0.93±0.1 (91.5%*) 4.5 Summary of the API fluid loss study of different NPs in Invert emulsion The most frequently encountered problems while drilling oil and gas wells are lost circulation causing substantial financial loss. This problem occurs during the uncontrolled flow of drilling fluids into vicinity of porous and permeable zones. The proposed method incorporates using different nanoparticles in drilling fluid to decrease fluid penetration and mud cake thickness. In the current study, the multifunction of NPs in drilling fluid system is considered as the new hotspot in the field. Results show that existence of nanoparticles caused the amount of fluid loss reduction and mud cake thickness to decrease. By forming a thin, low permeability filter cake NP-based fluid simulates sealing pores and other openings in the formations penetrated by the drill bit. Different NPs were used as bridging agent to control the fluid loss. Figure 4.29 and Figure 4.30 showed the effectiveness of different ex-situ and insitu NPs respectively in terms of fluid loss over a period of 30-min. 122

139 Fluid loss reduction, % Figure 4.29: LTLP fluid loss behavior of different ex-situ NPs in invert emulsion. 100 Fe(OH)3 CaCO3 (R2) CaCO3 (R5) FeS BaSO Fe(OH)3 CaCO3 (R2) CaCO3 (R5) FeS BaSO4 Figure 4.30: LTLP fluid loss behavior of different in-situ NPs in invert emulsion. The nanoparticle concentration in drilling fluid was varied from less than 1 wt% to 4 wt% (1 wt% Fe(OH) 3 NPs, 4 wt% CaCO 3 NPs, 3 wt% BaSO 4 NPs and 3 wt% FeS NPs). From the experimental trials, it can be concluded that zero spurt loss was achieved with thin mud cake in all NP-based fluid. However, in-situ NPs responded with lower fluid 123

140 loss than ex-situ NPs. Due to different physio-chemical nature, sizes and interaction potential with clays caused the NPs to behave differently. Therefore, optimum concentrations of NPs were required to meet the desired fluid loss control property. If the NPs formed were not well dispersed, stabilization of fluid systems were hindered and then particles tempted to agglomerate and precipitate. Figure 4.31 shows the different ex-situ prepared NPs and their stability performance. Adequate usage of emulsifiers prevented the phase separation through steric or electrostatic means of adsorbed dispersed NPs on clay matrix and/or emulsifiers surface. Increased viscosity of the continuous phase system can also prevent separation of dispersed phase (Riley et al., 2012). As nanoparticles addition in drilling fluid did not increase the fluid viscosity significantly, it is therefore, best prefer in our current works to support steric or electrostatic way of NPs stabilization. Mud having low filtration characteristics deposited as thick filter cakes (Nyland et al.,1988). Conversely, good filtration characterized by all the NP-based fluids yielded thin mud cakes as shown in Figure The thickness of the mud cake and its integrity can reveal that NPs deposited on the cake with optimum concentration establish an effective seal. For combating formation damage, NP-based invert emulsion as well as water based mud would offer better protection. The filtrate invasion from the invert emulsion would be less at the downhole pressure and offer better protecting against differential pressure sticking. 124

141 FeS NPs BaSO 4 NPs CaCO 3 NPs Fe(OH) 3 NPs Figure 4.31: Different NPs and NPs-containing drilling fluid stability evaluation. BaSO4 NPs filter cake FeS NPs filter cake Fe(OH)3 NPs filter cake CaCO3NPs filter cake Base filter cake filter Figure 4.32: NPs-containing drilling fluid filter cakes (thickness <1 mm). 125

142 Chapter Five: Modelling In this chapter, Darcy filtration equation was used to model drilling fluid loss for LTLP filtration experiments only. Based on the results, permeability of the mud cake at different times was estimated. In this section, time-dependent behavior of filter cake build up model was also evaluated. An attempt to address how the nanoparticles transport during filtration was made. Bingham plastic rheology was used to predict the relationship between the shear rate and shear stress for the drilling fluids under study and allowed to calculate several other important attributes of the fluid. 5.1 LTLP API filtration model using Darcy s law Drilling fluid filtration rate and its behavior with respect to time were estimated from the experimental results using Darcy s law (Maduka, 2010; Kumar, 2010; Hoff et al., 2005; Donaldson and Chernoglazov, 1987; Ferguson and Klotz, 1954; Williams and Cannon, 1938). The LTLP API filtration test was static, dead end filtration, as the mud was not circulated during filtration and the filter cake was allowed to grow without disruption by shear forces. Under this condition, certain volume of a stable suspension is filtered out against a permeable substrate, e.g. filter paper, with time. At time t, certain volume of filtrate is removed by filtration at constant temperature and pressure (25 C, 100 Psi). During the filtration process, filter cake accumulates and the volume of the mud sample in the filter press is decreased. Assuming constant density (temperature must be constant in order for Darcy s law to be valid. If temperature changes with time, density is also a function of time), the material balance equation expressed as a volume balance for mud filtration process can be written as follows. Drilling fluid volume in the filter press = Wet Filter cake volume + Filtrate Volume 126

143 The filter cake is assumed uniform throughout and the rate of growth of the filter cake is proportional to the rate of filtrate. According to the volume balance, if a unit volume of a stable suspension of solids is filtered against a permeable substrate and x volume of filtrate is collected, then 1-x volume of cake (solids plus liquid) will be deposited on the substrate. The following equation can be written (Maduka, 2010; Hoff et al., 2005). Q Q C f x 1- x r (E 5.1) where Q c and Q f are the volumes of the filter cake and filtrate at a given time, respectively, r is the ratio between the volume of the filter cake at a given time to the volume of the fluid filtrated in the filter press. From our experimental works and filteration curves provided by Barkman and Davidson(1972), we can assume the following criterion for the ratio of Q C. Q f if Q Q C early stage of filtration f <1 ; initial fluid pass through the filter cake and happens only at the if Q Q C f =1 ; fluid loss during filtration approximated by the linear relationship between volume of filtrate vs. time. It can be termed as equilibrium filtration if Q Q C f >1 ; saturation occurs, curve departs from linear relationship between volume of filtrate vs. time and slows fluid loss due to the compact cake layer formation. Filtrate decrease with increase of cake volume 127

144 The cross sectional area of the filter cake A is constant under static filtration. The volume of the filter cake, Q c, is given by the product of cross sectional area of the filter press, A, and the thickness of the mud cake at a given time, h mc. Qc A.h mc (E 5.2) Therefore, h mc Qc Q f. r (E 5.3) A A From Darcy s law, the flow rate of filtrate through the mud cake (an unconsolidated porous medium) is given by, dq dt f ka P (E 5.4) h mc Substituting (E5.3) into (E5.4) gives, dq dt f 2 ka P (E 5.5) r Q f Integrating (E5.5) assuming constant permeability, viscosity and pressure difference gives, Q 2 f 2 2kA P t r (E 5.6) It should be noted that the P was maintained constant throughout the filtration process. Darcy s law is obtained empirically and defines the permeability k as a proportionality coefficient in the relationship between flow rate and pressure gradient (Costa, 2005). Cake permeability is much lower than the permeability of filter medium.finally, Darcy s 128

145 law under the above assumptions leads to the following expression of filtrate volume versus time. 2k P t Q f. A (E 5.7) r The rates of mud filtration and mud cake formation are both function of time and proportional to each other during filtration. Therefore, under equilibrium filtration assumption, r can be taken as 1 (Hoff et al., 2005) and consequently, Q / / 2k P k t ; where k A (E5.8) f. It is well known that when an external mud cake begins to form and grow, the filtrate volume is proportional to (Kumar, 2010; Hoff et al., 2005). From (E5.8) and (E5.3), the thickness of the mud cake, h mc, at any time, t, during the filtration process, can be simplified to, h mc 2 k Pt (E5.9) At the initial exposure of a permeable formation to a drilling fluid, three stages of mud cake build up evolve: 1) spurt loss, which corresponds to the initial loss of fluid to the formation, 2) buildup of filter cake, during which fluid filtration is proportional to the square root of time as reported by many researchers (Kumar, 2010; Hoff et al., 2005; ASME,2005) and 3) filter cake growth, which might be limited by the erosive action of mud stream within the dynamic context of real time drilling (Outmans, 1963). It should be noted that the last stage does not exist under static filtration. The surface of the dynamic filter cakes erode to an extent that depends on the shear stress exerted by the hydrodynamic force of the mud stream relative to the shear strength of cake s upper layers (Caenn et al., 2011). Spurt loss can be obtained by extrapolating filtrate volume versus t to zero time and is given approximately by the y-axis intercept of the plot as shown in Figures 5.1 and 5.2. In all cases the NP-based fluids were compared with the corresponding control DF samples. Although DF samples were composed using the 129

146 same constituents and obtained from the same suppliers, nevertheless, this does not guarantee no variation from one batch to another. Therefore, NP-based fluid performance was compared with respect to its own DF control samples. From the current experiments, addition of NPs significantly reduced the bridging time and, therefore, the spurt loss. In Figure 5.2, symbols (R2) and (R5) stand for the reactions used in the experimental methods described in Chapter 3. The plot of filtrate volume, Q f, versus t suggests a different filtration mechanism in the presence of NPs. The very low Y-intercept for the case were NPs are used suggest that time needed to completely bridge the porous mud cake to reduce the fluid loss is much faster in case of NPmediated DF, and more specifically in the case of Fe(OH) 3 NPs relative to CaCO 3 NPs. This suggests that Fe(OH) 3 NPs are more effective than CaCO 3 NPs at bridging across the face of fracture of porous formation. A coefficient of determination, R 2, approaching 1 for a straight line fit, not going through the origin, between Q f and t with positive intercept in the case of no NPs, i.e. control samples and drilling fluid with LCM, indicates that spurt loss is important, whereas for the NP-based fluids it was negligible. Spurt loss is largely caused by the tendency of the particles to pass through the filter paper until its pores become partially plugged, which eventually leads to linear relation between filtrate volume and square root of time. Typically, a linear relationship w.r.t. square-root of time represents wall building fluids (Clark,1990; Chin, 1995). Conversely, a region of nonlinear relationship appeared in the case of NP-based fluid at the beginning of filtration due to the absence of spurt loss. An extrapolation of the linear portion of these curves can lead to a negative spurt loss value. So it is evident from the trend that early portion of curve did not follow the Darcy s law. Therefore, (E5.9) does not provide a good estimate of cake growth in the case of NP-based mud. The role of Brownian diffusion during the initiation of filter cake will be explained in the next section. 130

147 Volume of filtrate, Q f (cm³) Volume of filtrate, Q f (cm³) DF DF+LCM DF+Ex-situ NPs DF+In-situ NPs No spurt loss R² = 0.99 R² = 0.98 R² = 0.99 R² = Time ( ), sec½ Figure 5.1: Filtrate volume variation with square root of time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs DF DF+Ex-situ NPs (R2) DF+In-situ NPs (R2) R² = 0.98 R² = 0.98 R² = 0.99 R² = Time ( ), sec½ Figure 5.2: Filtrate volume variation with square root of time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs. (R2) and (R5) refer to the reaction used to prepare the CaCO 3 NPs per Section 3.2. The permeability of filter cake is the fundamental parameter that controls static filtration (Caenn et al., 2011; Byck, 1940). During filtration of mud with and without conventional LCMs, the trend seem to follow Darcy s equation throughout, and mud cake permeability (fitted parameter) was reduced exponentially with time as shown in Figures 131

148 Permeability of mud cake (nd) 5.3 and 5.4. The figures show a different behaviour for the mud cake permeability with / time for the NP-based fluid. The term k were determined during each filtration times from the data points of the Figure 5.1 and 5.2. Then using (E5.8), mud cakes permeabilities were estimated at each time interval. The results were presented for the sake of simple comparison between the drilling fluid with and without NPs using Darcy equation. Spurt loss was nil during the initiation of the filter cake of NP-based mud, and when filtration was stopped at a certain time, the mud cake growth reached a constant value. It appears that the highly compacted filter cake contributed to significantly less permeability and static filtration rate as evident from the smaller thickness of the filter cake DF DF+LCM DF+Ex-situ NPs DF+In-situ NPs Time (sec) Figure 5.3: Mud cake permeability variation with time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs. Permeability obtained from fitting E

149 Permeability of mud cake (nd) Time (sec) DF DF+Ex-situ NPs (R2) DF+In-situ NPs (R2) DF+In-situ NPs(R5) Figure 5.4: Mud cake permeability variation with time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs. Permeability obtained from fitting E5.8. (R2) and (R5) refer to the raction used to prepare the CaCO 3 NPs per Section 3.2. The permeability was calculated from the equation (E5.8) and compared with the base drilling fluid after 30 min filtration as shown in Table 5.1. It is shown that more than 90% mud cake premeability reduction was achieved in the presence of NPs, whereas conventional LCM reduced the permeability by 77%. The extent of permeability reduction varied with NP type and method of preparation. Data in Table 5.1 suggest potential use of NPs to plugg shale formation. As indicated in the results section, NPs are capable of providing effective sealing since they displayed wide range of size distribution, which could effectively bridge between clay particles initially forming the cake. Table 5.1: Permeability reduction of mud cake in the presence and absence of NPs. (R2) and (R5) refer to the reaction used to prepare the CaCO 3 NPs per Section 3.2. NPs Test Fluid Cake Permeability after 30 min filtration (nd) % Reduction in Permeability DF(Control samples) 2.59X DF+LCM 5.84 X Fe(OH) 3 DF+Ex-situ NPs 2.59 X DF+In-situ NPs 1.62 X DF( Control samples) 1.04 X DF+Ex-situ NPs (R2) 5.84 X CaCO 3 DF+In-situ NPs (R2) 2.59 X DF+In-situ NPs (R5) 2.59 X

150 On the other hand, inappropriate size of plugging materials results in the formation of a thick and permeable filter cake leading to continuous filtration, which seems to be the case for drilling fluids alone and DF with conventional LCMs. Therefore, pore throat diameter of formation must be known to help ensuring effective bridging. A general rule of thumb for estimating the unknown pore throat diameter (microns) is to take the square root of the permeability in milli Darcies as per (E5.10). For effective bridging 20-30% by weight of the bridging material should be one-third of the pore size in microns as per (E5.11) (kumar, 2010). Pore throat diameter (microns) = Permeabili ty (md) (E5.10) D(50) = Pore diameter 3 (E 5.11) Following Darcy equation, (E5.4), calculation gave permeability available of the filter cake of drilling fluid control sample after 30 min filtration was approximately from to md= 102 to 51 nd. This permeability is low and actually is of the same order magnitude of as in shale (Chenevert and Sharma, 1991). According to the above equations, estimated pore throat size of the control sample mud cake after filtration is nm. It does suggest that pore throat sizes are on the nm scale within the cake. NP-based drilling fluids contain 70% of NPs with sizes ranging from 1 to 30 nm as shown in Figure 4.4, which could easily ensure effective bridging and plugging of the pores. Therefore, when NPs were introduced, further reduction in cake permeability occurred, which was not achieved by using conventional LCMs. Materials accumulation, which is commonly referred to as fouling may arise from particles deposits on the filter surface, adsorbed on the cake surface, or within the cake pores. The concentrations of fouling materials at the cake surface typically increases with time. Consequently, resistance to permeate flow increases with time. NPs accumulate in the cake surface due to convective deposition and reach a threshold where the formation of cake layer can be predicted. This cake provides significant 134

151 resistance to fluid loss. Cake growth performance can be evaluated in terms of permeate flux as follows: Permeate (filtrate) flux = V t. S (E5.12) where V is the volume of permeate in ml, t is the permeate collection time in sec and S is the filter effective surface area = cm 2, from LTLP apparatus. Figure 5.5 shows that permeate flux decreased with time probably due to cake layers formation. The results show that the flux declined rapidly during the first 300 and 450 sec for DF and DF+LCM, respectively, followed by gradual decrease during the period of 500 and 1500 sec. This type of decline is indicative of fouling, or resistance, gradually building up on the surface of the filter paper. Although not on the same scale, permeate flux for DF+NPs experienced sudden increase with time and approached a steady flow as shown in Figures 5.5. The trend in permeate flow for NP-containing fluids can only be explained by changes in cake structure. This influence of particle size on the permeate flux was also described by Sethi (1997). Smaller particles (less than 0.01 µm) formed thin filter cakes, which resulted in higher permeate flux, whereas monotonic decline in flux occurred when larger particles (greater than 1 µm) were used. 135

152 NPs+DF Figure 5.5: Comparison of permeate (filtrate) flux with time in the presence and absence of in-situ and ex-situ prepared Fe(OH) 3 NPs. NPs+DF Figure 5.6: Comparison of permeate (filtrate) flux with time in the presence and absence of in-situ and ex-situ prepared CaCO 3 NPs. (R2) and (R5) refer to the reaction used to prepare the CaCO 3 NPs per Section

153 It is believed that the cake build up was first initiated by clay particles, which were large particles, even before the actual filtration started. These particles may deposit under gravity effect by virtue of their large size. During the NP-based fluid filtration, NPs move towards the large particles only by virtue of bulk flow. Similar observation was reported by Chellam and Wisber (1997) for smaller particles transport in cross flow membrane filters. Moreover, with large accessible surface area NPs can be adsorbed onto the cake surface readily following travelling for short distances only. This leads to plugging formation near the surface of the filter cake at early stages of its maturity and Brownian motion becomes important in controlling particle deposition, since the pore openings are generally not large. Tran (2011) modeled the mud cake thickness for deadend filtration as an exponential function of time until it attains its maximum thickness. Based on our observation, the mud cake without NPs reached its maximum permeability reduction after 30 min, whereas more reduction of the mud cake permeability was attained when NPs were used. Therefore, a phenomenological model for cake growth of NP-based fluid is proposed based on the experimental results obtained in this work. Similar modelling approach was generally used for population and biomass growth (Edwards and Edwards, 2011; Spier et al., 2009). The initial stage of growth is approximately exponential, and then as saturation begins, the growth slows and at maturity, growth stops. With this in mind, the following equation can be written to describe cake thickness in the presence of NPs. dhmc h mc ghmc 1 (E5.13) dt X Equation (E5.13) can be integrated using separation of variables approach as follows. dh h 1 X mc h mc mc gdt (E 5.14) 137

154 Rearranging the LHS of (E5.14) gives, h mc 1 X 1 1 (E5.15) hmc h X h h X h 1 mc mc mc mc X The steps below follow, dh h mc mc dh X h mc mc g dt (E 5.16) X - h h mc mc ln h mc X - h ln h X-h gt C ln (E5.17) mc mc mc X - h gt C h mc mc gt C (E5.18) e (E5.19) gt c Ae, where A e h mc gt Ae X (E5.20) 1 (E5.21) h mc (t) 1 X Ae gt (E5.22) X - h where, A relative cake growth rate= h 0 0, h 0 = initial cake growth at time t=0 measured experimentally before the actual filtration starts, i.e. h mc (0) = h 0 and relative cake growth rate coefficient, g, is obtained from the exponential differential equation dh mc =ghmc, g is positive and X is the maximum cake thickness in mm after 30 min. dt 138

155 Finally, a model for cake thickness estimation in the presence of NPs can be written as follows. h mc (t) 1 X X - h h 0 0 e gt (E5.23) Assuming that all mud cakes attain their maximum thickness of X (mm) after 30 min of mud filtration, the proposed cake thickness model (E5.23) can be used as the best approximation to the mud cake deposition throughout the static filtration period for NP based fluid. Bezemer and Havenaar (1966) proposed that for certain mud additives, the mud cake permeabilities can be reduced significantly during the mud filtration process. Equation (E5.10) shows that mud cake build up can be modeled as an exponential growth. Mud cake porosity decreases as the NPs deposition increases and, consequently, the filtrate flow through the cake decreases. With the above assumption, the increase in cake layer thickness over time can be fitted from the initial cake thickness until a steady state region is reached. From the API LTLP filter press experiments after 30 min, the filter cake thickness was measured to be 0.35 mm for the Fe(OH) 3 NP-based fluid and 0.52 mm for the CaCO 3 NP-based fluid as shown in Figures 5.7. The model, (E5.23), was used to estimate the time for filter cake buildup with the following parameters h 0 =0.01 mm (initial cake growth at time t=0 measured experimentally before the actual filtration starts which is natural cake build up) and X =0.35 mm for Fe(OH) 3 NP-based fluid and h 0 =0.01 mm (initial cake growth at time t=0 measured experimentally before the actual filtration starts which is natural cake build up) and X =0.52 mm for CaCO 3 NP-based fluid. From the model curves mud cake thickness attained its maximum thickness, h mc = 0.35 mm at 40 min for Fe(OH) 3 and 0.52 mm 40 min for CaCO 3 NP-based fluid, showing a fair agreement with the experiments. The time-dependent behavior of the filter cake build up of NP-based fluids to a maximum value was captured. Similar time dependent mud cake growth behavior was also investigated in the literature (Tran, 2011; Wu et al., 2005 ; Mackley and Sherman,1992). 139

156 0.52 mm 0.52 mm 0.35 mm 0.35 mm Figure 5.7: Variation of Mud cake thickness with time for NP-based fluid. 5.2 NP based fluid transport using Stoke-Einstein equation Nanoparticle transport during filtration is predominantly influenced by convection and Brownian diffusion with negligible contributions from gravitational settlings and shear induced diffusion (Hwang et al., 1998; Mcdonogh et al., 1984; Song and Elimelech, 1995). Previous studies found that between microparticle and nanoparticle transport models, particulate deposition greatly depends on the particle size (Ding and Wen, 2005; Kleinstreuer et al., 2008). This current model suggested that the nanoparticles get dispersed due to diffusion and convection, whereas microparticle transport is governed by convection and sedimentation. For micron sized particles Brownian diffusion mechanism is not important (Ives, 1970). 140

157 The general diffusion equation for nanoparticle transport can be written as t C NP. J 0 (E5.24) At a given location within the flow, the total flux, J of particle migration can also be described at any time as (Zamani, 2009; Ding and Wen, 2005), J J Diffusion J advection (E5.25) The diffusion flux of NPs, J Diffusion (moles/cm 2 -s), can be expressed as a function of the concentration gradient using the first law of Fick, which in one dimension can be written as J Diffusion CNP -DNP (E5.26) x For unsteady diffusion, Fick s second law is, C t NP D NP C x x NP (E5.27) Equation (E5.26) can be simplified as: J Diffusion D. C (E5.28) NP NP where, DNP is the diffusion co-efficient of nanoparticles due to Brownian effect. In the second term of (E5.25), J advection, is the overall convection or flow and considered as an associated flux called advection flux and can be expressed as: J advection= U. C NP (E5.29) where, U is the particle velocity induced by fluid flow (cm/s). 141

158 Then, the convection diffusion, equation (E 5.24), simplifies to C t NP. ( D. C U. C ) 0 (E 5.30) NP NP NP Equation E5.30 can be further simplified to (Ghesmat et al., 2011; Zamani, 2009; Bird et al., 2002): C t NP.(U.C 2 NP) DNP. CNP (E 5.31) Diffusion happens randomly due to molecular motion. In the absence of surface interaction forces, nanoparticles diffusivity due to Brownian motion replaces ordinary diffusion coefficient (Tien, 1989). Small particles can be diffused to the cake surface where they can stick. Therefore, the diffusion coefficient of nanoparticles in liquid can be calculated by using the Stokes-Einstein relationship: D NP k T 3 d B (E 5.32) NP where k B = 1.38X10-23 J/K is the Boltzmann constant, T is the absolute temperature, μ is the dynamic viscosity, and d NP is the nanoparticle diameter. If mass deposition rate (micro or nanoparticles) from the drilling fluid over API filter paper having 2.7 μm grain size is considered, Peclet number, Pe, for mass transfer is defined as dgu Pe (E 5.33) D NP where, is the characteristic velocity determined from the filtrate flow rate till 30 min and is the filter grain diameter. Peclet number reflects the ratio of particle migration due to convection to that due to Brownian diffusion. If Pe >>1, transport by convection and/or sedimentation, in the case of microparticles, is the main driver, whereas if Pe <<1, diffusion dominates transport (Russel et al., 1999). Pe was calculated using 142

159 (E5.33) employing Brownian diffusion coefficient, (E5.32) and base oil viscosity of 3.44 cp at 25 C and different particle sizes at LTLP API filtration condition. The effect of Peclet number is associated mainly with particle size as shown in Figures 5.8 and 5.9. The calculated data tables were listed in Appendix C. From Figure 5.8 it can be shown that Peclet number increases rapidly with increasing particle sizes. Both DF control samples exhibited similar trend close to each other. Particles in the micro domain, e.g μm which is typical for conventional LCMs, display relatively high Peclet number, Pe>>1. This, in turn, suggests that for LCM and clay particles the effect of Brownian motion is not important. Conversely, many earlier studies have found that the migration of NPs can be described by Brownian motion (Phillips et al., 1992; Lam et al., 2004; Ding and Wen, 2005). In the present study, in the low-pe regime, dispersion, molecular diffusion, plays a very important role in NPs transport as shown in Figure 5.9. Although both Fe(OH) 3 and CaCO 3 NPs show a similar trend, the slight differences are assumed to be their size ranges. Migration of nanoparticles to the filters cake may also encourage formation of clusters/aggregates due to diffusion on the surface. Microscopically, it is the balance between different forces (hydrodynamic, van der Waals, electrostatic, steric due to the presence of surfactant rich NPs) that affects the force-distance dependency between the particles. Note that shear thinning behavior of fluid was not considered in this study. This is because particle concentration of NPs used in drilling fluid formulation, 1-4 wt%, was low and no significant effect on fluid viscosity was reported as detailed in the results and discussion section. 143

160 Peclet number,pe Peclet number,pe d p, microns Figure 5.8: Effect of particle sizes of DF (d p =2-200 μm in DF) on Peclet number. d p, microns Figure 5.9: Effect of Fe(OH) 3 and CaCO 3 NPs size in DF ranges from μm (1-300 nm) on Peclet number. 144