Polymeric and low molecular weight shale inhibitors: A review

Fuel 251 (2019) 187–217

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Review article

Polymeric and low molecular weight shale inhibitors: A review a

b,⁎

Hafiz Mudaser Ahmed , Muhammad Shahzad Kamal , Mamdouh Al-Harthi a b

a,⁎

T

Department of Chemical Engineering, King Fahd University of Petroleum & Minerals, 31261 Dhahran, Saudi Arabia Center for Integrative Petroleum Research, King Fahd University of Petroleum & Minerals, 31261 Dhahran, Saudi Arabia

ARTICLE INFO

ABSTRACT

Keywords: Drilling fluids Polymers Clay swelling Inhibitors Oil and gas exploration

Water-based drilling fluids (WBDFs) are widely used for drilling oil and gas wells. Water-based drilling fluids are considered economical and environmentally friendly compared to synthetic and oil-based drilling fluids. Water is one of the major constituents of WBDFs but causes the swelling of clay minerals in wellbore formations. Clay swelling in the wellbore has detrimental impacts on drilling operations and it leads to excessive costs of drilling operations and oil well construction. During drilling operations, the interactions of drilling fluid and clay swelling can be prevented by using various inhibiting agents that reduce the interactions of water contents with the wellbore. To develop high-performance shale inhibitors that can significantly reduce clay swelling, drilling operation costs, and environmental impacts, a significant amount of research on the industrial and academic level has been done. The available literature lacks a comprehensive understanding of polymeric, amine-based, ionic liquids, and surfactant-based shale inhibitors for the oil field applications. This review explains the mechanisms of clay swelling, techniques used for the measurement of clay swelling, and various inhibitors used to prevent clay swelling. Additionally, the effects on the process for various polymer-based inhibitors, nitrogenbased inhibitors, ionic liquids, and surfactants based shale inhibitors have been studied in detail.

1. Introduction Oil and gas well drilling require different drilling fluids to perform various functions: to maintain the rheology of fluids [1–6], manage the hydrostatic pressure in the wellbore, lubricate the drilling bit, prevent the invasion of fluid loss into formations, transport rock cuttings to the surface, and prevent the swelling of shale formations [7–12]. Drilling fluids are broadly classified as oil-based drilling fluids (OBDFs) or water-based drilling fluids (WBDFs). Oil-based drilling fluids have superior inhibition properties, excellent lubricity, and high-temperature stability. However, the increasing demands for environmental legislation and excessive costs restrict OBDFs in drilling applications. Waterbased drilling fluids are widely employed for drilling operations because of their environmentally friendly nature, remarkable rheological properties, and excellent performance [13–24]. However, the use of WBDFs for reactive shale formations may result in detrimental impacts to wellbore stability. An oil and gas drilling section composed of 75% shale formations caused 90% wellbore instability problems during the drilling process [25]. The primary issue of WBDFs is shale swelling, which causes instability problems in the wellbore during the drilling process such as sloughing, bit balling, caving, high drag and torque, stuck pipe, and disintegration of shale

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cuttings due to the water adsorption of sensitive shales [26,27]. The shale swelling occurs due to the presence of various clay minerals in the shale. Clay swelling and wellbore instability also affect hole cleaning efficiency due to the agglomeration of shale cuttings. The worst-case scenario of wellbore instability includes the loss of drilling assembly, lost circulation, and the chances of losing part of the hole or the complete well. All wellbore instability problems seriously affect the drilling rate and contribute to the increased exploration and production costs [28]. Numerous studies reveal that wellbore instability problems are 10% higher in cost compared to the well costs which are usually greater than $1 billion per annum [29]. Therefore, the development of a green shale swelling inhibitor with enhanced inhibiting capacity is desired for effective drilling fluid properties and to overcome the cost issues of wellbore instability. Traditionally used shale inhibitors include various electrolytes such as sodium chloride, potassium chloride, and divalent brine electrolyte for water sensitive shale formations. These electrolytes are used in various concentrations based on the type of shale formation and the additives of WBDFs. The high concentration of these electrolytes prevents the hydration and swelling of water sensitive shale formation. However, a high concentration of these electrolytes in drilling fluids results in flocculation of clay minerals which affects the properties of

Corresponding authors. E-mail addresses: [email protected] (M.S. Kamal), [email protected] (M. Al-Harthi).

https://doi.org/10.1016/j.fuel.2019.04.038 Received 14 January 2019; Received in revised form 16 March 2019; Accepted 5 April 2019 0016-2361/ © 2019 Elsevier Ltd. All rights reserved.

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Fig. 1. Classification of shale inhibitors.

that bio-surfactant has excellent inhibition properties in the drilling fluids [41]. In the past few years, other alternatives have also been developed for high-performance shale inhibitions such as surfactants, copolymers, ionic liquids, and modified nanoparticles [42–44]. Few studies have been reported in the last decade related to the swelling of clays, borehole stability, and shale inhibitors. Anderson et al. has studied the swelling of clays based on experimental and theoretical techniques emphasizing on the swelling of minerals under crystalline regime, nature of charge and charge density [45]. Another recent study presented the borehole instability issues that lead to the shale swelling and hydration. The effect of various types of water-based drilling muds are employed to conventional drilling operations and high-temperature/ high-pressure drilling wells [27]. The available literature lacks the comprehensive understanding of polymeric and amine-based, ionic liquids and surfactant-based shale inhibitors for the oil field applications. An extensive amount of literature is available for describing shale swelling, shale inhibition and field applications of shale inhibitors [46,47]. In this review, a comprehensive critical analysis of the available information in the literature is presented to address the swelling and inhibition mechanism of clays and related issues of oilfield geochemistry. The first section discusses the composition, structure, and chemistry of clay minerals followed by the experimental and analytical techniques commonly used to investigate and characterize the performance of shale inhibitors. The classification of various shale inhibitors is discussed in detail which includes amine-based shale inhibitors, polymer-based shale inhibitors and other alternatives which have recently been employed for shale inhibition such as surfactants, and ionic liquids, the purpose of discussing various classes of shale inhibitors is to enlighten the performance evaluation pros and cons under different drilling conditions. Finally, we discuss challenges and prospects in the development of environmentally friendly and cost-effective shale inhibitors. The classification of different shale inhibitors is shown in the Fig. 1

the drilling fluid causing high fluid loss volume and loss of thixotropy. A high concentration of salts also affects the rheological properties of bentonite based drilling fluids, marine environment, and shale cutting lifting capacity of drilling fluids [30]. Therefore, polymer/salt systems are widely utilized to overcome the issues related to the high concentration of electrolytes in WBDFs. Polymers are employed to modify the rheological properties such as viscosity, yield stress and gel strength. High molecular weight and salt resistant polymers are used in the formulation of drilling fluids that retain the rheological properties [31–33]. Over the past few decades, a wide range of methodologies has been proposed with high concentrations of organic salts, inorganic salts, and various kinds of polymer-based additives for shale inhibition [34–38]. However, these methodologies have not been effective for inhibiting the sensitive shale formations and have many other limitations. Among these approaches, when potassium chloride is combined with polyglycol, silicates and partially hydrolyzed polyacrylamide (PHPA), superior inhibition results are obtained with synergistic effects. Nitrogen-based derivatives were introduced recently with effective shale inhibition characteristics. Among these, ammonium chloride was the simplest nitrogen-based derivative and has been used for several years as a shale inhibitor. Recently employed low molecular mass polyether diamine has significant shale inhibition properties in WBDFs compared to the oil-based drilling fluids. Recently, a new amine terminated polyether (ATPE) shale inhibitor was synthesized in the laboratory for the inhibition of shale in water-based drilling fluid. The shale inhibition performance of ATPE was evaluated and compared with conventionally used shale inhibitors such as potassium chloride, polymeric alcohol, methane siliconic acid and potassium formate. Hot rolling dispersion test showed the superior inhibition capacity of ATPE compared to the conventionally used shale inhibitors [39]. In another study, a bio-surfactant was extracted from Korean red Ginseng root and used as potential additive in water-based drilling muds for the inhibition of shale swelling and hydration. The inhibition performance of biosurfactant was compared to the potassium chloride and Cetrimonium bromide cationic surfactant. Shale inhibition tests showed that biosurfactant was superior shale inhibitor compared to the Cetrimonium bromide and potassium chloride. The bio-surfactant produced the bigger size aggregates in relatively less time with less hydrophilicity and shale recovery which indicated the enhanced shale inhibition properties of extracted bio-surfactant [40]. Similarly, another bio-surfactant was extracted from mulberry leaf and evaluated as potential environmental friendly shale inhibitor. The inhibition results showed

2. Chemistry & types of clay minerals Clay minerals are phyllosilicates which consist of a layered structure of negatively charged octahedral sheets of alumina and tetrahedral sheets of silica [48,49]. In tetrahedral sheets, each tetrahedron comprises of a cation which is coordinated with four oxygen atoms and linked with other tetrahedrons by sharing three corners to make a continuous two-dimensional, hexagonal layer. The commonly found 188

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clay minerals is balanced by exchanging cations with the solution and cation exchange in the clay minerals according to the following: (i) is controlled by the rate of diffusion of metal cations (ii) follows stoichiometric rule (iii) is a reversible process (iv) is a selective process for cation and depends on the size of exchangeable cation. The chemical composition shows that clay minerals having a 1:1 layered structure of tetrahedral layer and octahedral layers show fewer interlayer cations, so the cation exchange capacity of these minerals is very small. Similarly, the chemical composition of clay minerals having a 2:1 layered structure of tetrahedral layers and octahedral layers contain a substantial negative charge on the layers which are attached to a substantial number of interlayer cations, so these clay minerals show high cation exchange capacity. A wide range of natural minerals exists which differ in chemical composition, layered arrangements, and type of interlayer cations. A general classification of clay minerals based on the structure, swelling properties, cation exchange capacity, and SEM images are given below, for example, see the smectite, illite, kaolinite, and chlorite in Table 1 and Fig. 3. Studies show that clay minerals with a 2:1 layered structure (smectite) are more susceptible to swelling and offer considerable wellbore instability problems during drilling operations. Fig. 4 shows the layered structure of smectite clay. The main component of smectite clay is montmorillonite with chemical formula (Na,Ca)0,3(Al,Mg)2Si4O10(OH)2·nH2O. When the smectite clay swells its swelled volume is many times higher than the original volume. Water molecules adsorb on the interlayers and increase the basal spacing which results in the large swelling of clay minerals. Smectite clay exists in various forms based on chemical compositions such as hectorite, beidellite, and montmorillonite. Montmorillonite can be further classified as Na-montmorillonite or Ca-montmorillonite and these two different forms have a different swelling index. The smectite clay which contains sodium ions between the interlayers shows the maximum potential of swelling compared to all other clay minerals. The swelling of smectite clay can be reduced by replacing sodium and calcium ions with potassium ions or other cationic ammonium ions. Illite has a layered structure in which an octahedral alumina sheet is sandwiched between two tetrahedral silica sheets. Chemically illite is depicted as (K,H3O)Al2(Si3Al)O10(H2O,OH)2 which predominantly occurs in most shales and clay sediments. Illite is formed in hydrothermal environments and extreme weathering conditions by the modification of muscovite and feldspar. Strong interlayer interactions exist between tetrahedral sheets of silica and octahedral sheets of alumina due to high charge density on silica sheets. Tetrahedral and octahedral sheets are connected by the tips of tetrahedral layers and the hydroxyl group of octahedral layers. Illite has less tendency to swell upon interacting with water because its lattice has a non-expanding nature and therefore the ability of water to migrate into the layers is less. The presence of potassium ions in the interlayer spaces prevents the hydration and swelling of illite. Chlorite clay has the chemical formula (Mg, Fe2+)5Al(AlSi3O10) (OH)8, which consists of a group of phyllosilicate minerals classified as nimite, chamosite, pennantite, and clinochlore. It has a layered structure comprised of an octahedral sheet of alumina sliced between tetrahedral sheets of silica. The interlayers interact with each other

Fig. 2. Sketches (a) Octahedral sheet (b) Tetrahedral sheet [54]. ©Elsevier. Reproduced by permission of Elsevier.

cations in the tetrahedral sheets include Fe+3, Al+3 or Si+4. In octahedral sheets, each octahedron contains one cation which is coordinated with six oxygen atoms and attached with the adjoining octahedrons by sharing the common edges. The commonly found cations in the octahedron are Fe+2, Fe+3, Mg+2 or Al+3. The specific arrangement of tetrahedral and octahedral sheets in the clay minerals produces several types of clay [50]. If the clay is made up of one octahedral layer and one tetrahedral layer, it is designated as 1:1 clay (or T-O clay). If the clay is made up of two tetrahedral layers and one octahedral layer and they are arranged so that one octahedral layer is sandwiched between two tetrahedral layers, it is designated as 2:1 clay (or T-O-T clay) [48,51]. The clay minerals have negatively charged tetrahedral and octahedral layers which are due to the isomorphic substitution of metal cations. In the case of the tetrahedral layer, Si+4 ions are replaced with Fe+3 or Al+3 ions, while in case of the octahedral layer, the Al+3 ions are substituted with Fe+2 or Mg+2 ions as shown in Fig. 2 [52]. The isomorphic substitution of metal cations in the layers structure of clay induces a 90–95% negative charge [53]. The interlayer metal cations of clay minerals are responsible for balancing the negative charge induced by the isomorphic substitution. The cation exchange capacity of clay minerals is the ability to exchange interlayer cations from solution. The physiochemical properties of clay minerals are affected by cation exchange capacity, the morphology of clay minerals, particle size, pH of the solution, dispersion, hydration, aggregation properties and swelling characteristics of clay minerals. The negative charge on the layers of Table 1 Clay minerals and properties [55] Clay minerals

Layer Arrangement

Cation Exchange Capacity

Surface Area (m2/g)

Density (g/cm3)

Layer Thickness (Å)

Chemical Formula

Smectite

2:1

60–100

700

2–2.7

12–14

Illite

2:1

20–40

100

2.6–2.9

10

Chlorite Kaolinite

2:1 1:1

10–30 3–15

100 20

2.6–2.8 2.5–2.7

14 7

(Na, Ca)0.3(Al, Mg)2 (Si4O10) (OH)2∙ n (H2O) (K, H3O) (Al, Mg, Fe)2 (Si, Al)4O10[(OH)2 ∙ (H2O)] (Mg, Fe2+)5Al(AlSi3O10) (OH)8 Al2Si2O5(OH)4

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Fig. 3. SEM images of different clay minerals (a) smectite (b) chlorite (c) illite (d) kaolinite [56–58].

Fig. 4. Structure of smectite clay minerals [59]. ©Elsevier. Reproduced by permission of Elsevier.

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Fig. 5. Mechanism of swelling (a) Osmotic swelling (b) Crystalline swelling [198]. Open access article published by Springer-Verlag.

through hydrogen bonding and electrostatic force attractions. Chlorites have variable chemical and physical properties depending on a wide range of temperature, pressure, and composition. Kaolinite clay has the chemical formula Al2Si2O5(OH)4, which has a layered structure consisting of one layer of octahedral alumina and one layer of tetrahedral silica. It is formed by the weathering of aluminosilicates such as feldspar and physically it is a white and soft clay. Kaolinite has a low swelling capacity and ion exchange capacity (1–15 meq/100 g) compared to the smectite clay. When it interacts with water, kaolinite shows dispersion instead of swelling. The presence of kaolinite in shale is a great subject of interest and it also important in deciding wellbore mechanical strength. In summary, clay swelling is mainly related to clay minerals having a 2:1 structure due to their extensive swelling potential. The smectite clay (saturated sodium bentonite) can swell several times in volume compared to the un-hydrated clay and is considered as the main cause of shale instability in the drilling operations of oil and gas wells. Kaolinite has the least swelling potential due to its 1:1 structure.

increases clay volume. Typical osmotic swelling of clay minerals results in the increase in interlayer spaces from > 20 Ã to 30 Ã, which is usually higher than crystalline swelling of clay minerals. The smectite clay minerals saturated with sodium ions (also known as Na-montmorillonite) mostly show osmotic swelling in the drilling operations of oil and gas wells which leads to wellbore instability issues and in severe cases, the wellbore may collapse. Compared to sodium saturated smectite clay minerals, potassium smectite clay minerals do not show osmotic swelling in the presence of water and potassium ions are used to minimize the swelling of sodium saturated smectite clay in the wellbore. Crystalline swelling (surface hydration) of clay minerals occurs when clay interacts in an aqueous solution containing high concentrations of monovalent, divalent and multivalent ions. Cations in the interlays of clay minerals have a significant impact on the magnitude of crystalline swelling. Crystalline swelling of clay minerals occurs in a stepwise manner like the formation of the single layer, double layer and multilayer hydrates of cations in between the interlayer spaces. Quasicrystalline structures are formed by multiple layers of water molecules in the interlayer of clay minerals which results in the increase in interlayer spacing. Almost all types of clay minerals show crystalline swelling in the presence of aqueous solutions. Experiments have shown that smectite clay adsorbs water molecules and forms one, two, three and four layers of cation hydrates with the increase in relative humidity. Simulation results have also shown that the crystalline swelling of clay minerals occurs in a stepwise fashion and forms specific layers in between the interlayers which increase the interlayer spacing. Specific results of interlayer spacing for a crystalline swelling show that interlayer spacing ranges from 9 Ã to 20 Ã. The magnitude of clay swelling is also affected by the size, type, and charge of cations present in interlayers of clay minerals. The swelling of clay minerals starts with the hydration of interlayer cations and is affected by cation charge density. Clay minerals which contain monovalent cations and higher hydration energies have a high potential of swelling compared to the cations which have low hydration energies. In various simulation studies carried out to study the swelling behavior of montmorillonite clay, it has been observed that by increasing the concentration of water, clay minerals having lithium and sodium ions form one layer, two layers and three layers of cation hydrates. While in the case of potassium montmorillonite only one layer of cation hydrate was observed. In general, there are many variables that affect the swelling of clays,

3. Mechanism of clay swelling Hydration of clay minerals results in swelling which causes an increase of interlayer spacing and is mainly related to the type and concentration of interlayer cations. Interlayer cations of clay minerals can be hydrated in the presence of water and, as a result, the interlayer space of clay minerals increases which causes swelling. Experimental studies have shown that swelling of clay minerals can be explained in two separate ways: osmotic swelling and crystalline swelling. The schematic diagram of osmotic and crystalline swelling is given in Fig. 5. Osmotic swelling of clay minerals occurs due to the high concentrations of interlayer cations compared to the concentration of cations in the bulk solution. When the interlayer cation concentration is higher compared to the concentration of the surrounding solution, water molecules migrate between the interlayer spaces which results in an increase in interlayer spacing. Although there is no semipermeable membrane in the clay minerals, this mechanism of migration of water molecules is considered as osmotic due to the difference in the concentration of cations. Osmotic swelling of clay minerals is only attributed to certain classes of clays which contain exchangeable cations between the interlayer spaces. After hydrating, the osmotic swelling of clay minerals significantly 191

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such as the nature of interlayer cations, the concentration of cations, and the type of clay minerals. The swelling of clays can be inhibited by replacing the interlayer cations with other cations that have less affinity towards water and by coating the clay minerals with polymers which prevent the interactions of water with the clays. The subsequent section will explain the techniques of clay swelling and inhibition and various types of inhibitors.

4.4. Bulk hardness test The bulk hardness test evaluates the hardness of a shale cutting after immersing in drilling fluid. Shale can imbibe liquid from drilling fluids and become softer which increases the chances of wellbore instability during drilling operations [65]. Inhibitive properties and hardness of shale cuttings are inter-related. Therefore, a hardness test of a definite size shale cutting is performed after hot rolling the shale cuttings in the drilling fluid at 65 °C for 16 h. After that, the shale sample is sieved over 40 mesh screens, washed with brine and placed in the hardness tester. A torque wrench is used to extrude the cutting from the perforated plate. The wrench is rotated in a clockwise direction at a steady rate. The overall torque and number of rotations are measured as the hardness of a cutting is expressed in terms of the number of turns and torque required to extrude the cuttings from the perforated plate. The hardness of a shale sample depends on its recovery after the hot rolling. If the shale recovery is high, then the shale is considered hard and less prone to hydration and swelling [66].

4. Techniques for characterizing shale swelling and inhibition Shale stability is primarily affected by the swelling of clay minerals in the wellbore, and it is one of the main issues in drilling operations. Various experimental and analytical techniques are employed to study the swelling and inhibition of clay minerals. This section describes the various techniques to determine shale swelling and to evaluate the performance of different inhibitors. 4.1. Shale particle disintegration test The shale particle disintegration test describes the hydration and disintegration of a shale sample when immersed in drilling fluid. In this test, a cylindrical real field shale sample, of specific dimensions, is obtained after compressing the powder sample of shale in a shale compactor. The cylindrical shale sample is then placed in a steel jar and filled two-thirds full of drilling fluid. The jar is then placed on the rollers of a heating oven and the time is measured for the complete disintegration of the shale sample in the drilling fluid. The inhibitors are evaluated based on the resistance of the shale sample to disintegration. A good inhibitor is one which increases the time of complete shale disintegration [60].

4.5. Pore pressure transmission test The pore pressure transmission test is an important technique to evaluate the performance of shale inhibitors by blocking the pores of the shale sample. In this test, a shale sample (shale core) is placed in the core holder of a pore pressure transmission (PPT) device and drilling fluid is injected into the core through an upstream inlet. The upstream pressure of PPT is maintained at the value of 2 MPa while the downstream pressure is maintained at 1 MPa. The result of this experiment shows the rising curves between time and downstream pressure. The PPT device produces the curves that depict the shale sealing performance of drilling fluid and the curves are used to evaluate the change in downstream pressure over time [67]. The adsorption of inhibitors on the surface of clay minerals makes a more hydrophobic clay surface which is favorable to diminish pore pressure transmission.

4.2. Hot rolling dispersion test The hot rolling dispersion test is employed to study the inhibition performance of drilling fluid to prevent the hydration, disintegration, and dispersion of a shale cutting sample. In this test, a shale sample is ground to a fine powder and sieved with 20–30 mesh screens. The weighed shale sample (50 g) is placed in a steel cell along with 350 ml of WBDFs and the lid tightly screwed shut. The cell is then placed in the hot rolling oven at 95 °C for 16 h for aging according to API standards. After 16 h, the shale sample is gently washed with water and passed through 50 mesh screens. The shale sample retained over the screen is then dried at 60 °C in the oven. The final sample is weighed and compared with the original weight of the shale sample [44,60,61]. If the percentage is high, the dispersion of shale is less and the inhibitor is considered good.

4.6. Shale immersion test In this test, the shale sample is placed in freshly prepared drilling fluid for 24 h to study shale stability and fracture development in the sample. Usually, a shale sample immersed in water results in the erosion, cracks and macro pores. While, in the presence of an inhibitor, the shale sample is less likely to have erosion, cracks, and pores due to the formation of a protective layer on the shale sample [60,68]. 4.7. Measurement of interlayer spacing

4.3. Linear swelling test

XRD analysis is one of the important techniques to determine the inhibition capacity of a material by measuring its interlay spacing (dspacing) [69–72]. Inhibitor performance is determined by mixing it with montmorillonite in the presence of deionized water. The mixture of inhibitor and montmorillonite is stirred thoroughly for 24 h and then centrifuged at 8000 revolutions per minutes for 30 min and washed with deionized water three times to remove the unreacted inhibitor. After the centrifuging, the sediment of modified montmorillonite is then collected and divided in to two parts. One part is used to measure the XRD of the wet sample while another part is dried at 105 °C and after grinding to fine powder XRD analysis is carried out [69–73]. In the presence of shale inhibitor, the wet part of the clay sample indicates the decrement of interlayer spacing which implies that a shale inhibitor can expel the water from interlayers and results better adsorption capacity. While the dry part of clay sample shows an increment of interlayer spacing which indicates a superior ability of intercalation of clay minerals.

The linear shale swelling test is also performed to evaluate the characteristics of inhibitors. In this test, the linear swelling of a shale pellet is determined as a function of time and an inhibitor which gives minimum swelling of the shale sample is considered superior. In this test, a 5-gram shale sample is ground to a fine powder and placed into a pressure compactor by applying a pressure of 10 MPa for 5 min. Then the cylindrical disc of the shale sample is placed in a linear swelling meter in the presence of a prepared drilling fluid. The shale inhibition capacity depends on the reactivity of shale and the drilling fluid. The mineral composition of the shale sample is determined before performing the linear swelling experiment. Then drilling fluid additives and their quantities are added to the drilling fluid to minimize the swelling of the shale sample. The linear swelling meter measures the linear height for a specific period. The shale inhibitor which results in minimum linear swelling of shale sample is considered as good shale inhibitor [62–64]. 192

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4.8. Zeta potential measurement

attraction between water and clay minerals. High capillary suction time indicates that a large amount of water is attached to the clay minerals and less amount of free water available in the system. Shale inhibitors with less capillary suction time are considered good materials to prevent the hydration of clay minerals and inhibit the swelling of clay minerals. Capillary suction tests can be performed immediately after preparing the dispersion with a shale inhibitor or they can also be performed after 24 h or 48 h [78]. Shale inhibitors with less capillary suction time are considered good materials to prevent the hydration of clay minerals and inhibit the swelling of clay minerals [78].

Zeta potential is used to measure electro kinetic properties of shale inhibitors in the colloidal dispersion of shale. The various concentrations of shale inhibitors were added to the colloidal dispersions and stirred for 24 h before measuring the zeta potential at 25 °C. The shale inhibitors in the drilling fluid adsorb on the negatively charged surface of clay minerals in the shale and affect the colloidal stability and surface charge density. The reduction of the colloidal stability of clay leads to the increase in the endurance of shale disintegration and hydration [74]. The shale inhibitors adsorb on the surface of clay minerals which reduce the overall charge on clay minerals and making their surface hydrophobic in nature. Research has shown that if a surface charge of clay minerals is decreased by 20% then hydration and swelling of clay minerals can be inhibited [75].

4.12. Scanning electron microscope A scanning electron microscope (SEM) is an important instrument to perform high-resolution magnification analysis of a shale sample. The SEM analysis exhibits the presence of pores and embedded minerals in the shale sample. The compactness orientation and texture of the shale surface can be seen by SEM analysis. The presence of organic matter can be identified by the presence of oxygen and carbon in the shale sample. The shale inhibition is investigated by blocking the pores using shale inhibitors in the formulation. The presence of polymeric inhibitors in the water-based drilling fluid encapsulate the shale microstructure and pores and prevent the migration of drilling fluid in the pores of shale [79–81]. The formation of a thin layer of shale inhibitor on the shale sample is investigated by high magnification SEM analysis [63,70,82].

4.9. Wettability alteration test Shale inhibitors or stabilizers react with clay minerals in the shale and alter the wettability properties from a hydrophilic to a hydrophobic surface. To measure the hydrophobicity of shale reacted with the shale stabilizer, a wettability alteration test is employed. The test involves the formation of bentonite dispersions with different concentrations of shale inhibitors. Dispersions are stirred for 24 h. When an inhibitor is completely adsorbed on the clay particles and equilibrium reaches then a thin layer of dispersion is placed on the glass sheet and air dried. Upon drying, the dispersion forms a thin layer on the glass sheet. After that, about 5 μL droplet is placed on the thin layer with a syringe and the contact angle is measured using a contact angle goniometer high resolution camera. The shale inhibitor in the clay dispersion turns the clay particles hydrophobic by reacting with the shale inhibitor which further prevents the hydration and swelling of clays in the formations [71,76].

4.13. Water adsorption test The water adsorption test describes the reactivity of shale and the measurement is taken by a hydrometer which depicts the relative humidity of a shale sample [83]. The relative humidity of the shale sample is expressed percentage to give water adsorption [84]. Another way to measure water adsorption is to put the shale sample in water for a specific period of time. The weight of the shale sample is measured before and after the water adsorption test. The reactive shales have a high affinity to adsorb large amounts of water compared to the less reactive shales [85].

4.10. Fracture development test The fracture development test analyzes facture developments in the shale when it interacts with the drilling fluid. This test mainly emphasizes low reactivity and hard shale formations where stability issues are associated with the development of new fractures or the propagation of existing fractures. There are two techniques involved in the evaluation of fracture development when a shale sample interacts with different drilling fluid formulations. First, the shale sample is examined by microscope to determine the fracture development and other changes in the shale sample. Various microscopic measurements are taken to compare the parameters of the shale sample such as typical fracture width, number of fractures and maximum fracture width. Second, a time-lapsed photographic (TLP) technique is utilized to visualize the apparent changes in the shale sample. The fracture development test reflects the stability and fracture of the shale sample in the presence of diverse drilling fluids containing shale inhibitors [77].

4.14. Cation exchange capacity The cation exchange capacity of shale is a measure of the exchangeable cation present in the clay minerals of the shale sample. The most commonly available cations include sodium, potassium, calcium, iron, and magnesium. These cations are present in the interlayers of clay minerals and neutralize the negative charge of clay minerals produced by the isomorphic substitution of cations. The reactive clays such as montmorillonite and bentonite show high cation exchange capacity which is expressed as milliequivalent per 100 g of clay. The cation exchange capacity of clay minerals is determined by API standards using the methylene blue test (MBT). Shale is ground to a fine powder and a small quantity of powder (2 g) is mixed in the water along with sulfuric acid and hydrogen peroxide. The mixture is then boiled for a few minutes and cooled to room temperature. The mixture is then titrated against the methylene blue solution. The endpoint of the titration is determined by putting a drop of the mixture on filter paper which results in a light green or blue color halo sphere around the droplet. The reactive clays show high cation exchange capacity which also depict the affinity of hydration and swelling upon interacting with water. The clay minerals which show low cation exchange capacity values are less reactive but brittle. The less reactive clays in the shale sample are more susceptible to dispersion upon interacting with water. The cation exchange capacity range of various clay minerals is mentioned in the above section [86–88].

4.11. Capillary suction test A capillary suction test (CST) is performed by a device that measures the time of clay slurry or shale to travel across a filter paper. The capillary suction test results can be utilized to study the reactivity of shale samples with a single drilling fluid or to study the inhibition characteristics of different drilling fluids with a single shale sample. In this experiment, 5 ml of clay dispersion containing an inhibitor is placed inside the cylinder having filter paper of a specific thickness and two electrodes (both connected to a timer) are attached to the cylinder at the position of 0.5 and 1 cm from one edge of the cylinder. The electrodes measure the time required to travel through the free water from one electrode to the other. A short capillary time indicates the presence of a large amount of free water available in the system and less 193

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5. Classification of shale inhibitors

which shale becomes harder after interacting with inhibitor molecules and as a result of shale hardening shale dispersion and swelling is reduced [96]. Glycols, ranging from a simple ethylene glycol to a very complex polyhydroxy glycols are used for shale inhibition applications, including other polymers such as polyethylene and poly propylene oxide which are used to enhance shale inhibition capacity. Glycols have diverse molecular structures with different molecular weights but for shale inhibition applications low molecular weight glycols are preferred. Low molecular weight glycols are liquids which mix easily with water-based drilling fluids. Also, low molecular weight glycols can penetrate the matrix of shale while high molecular weight glycols are only adsorbed on the surface of the shale matrix. The mechanism of shale inhibition by glycols can be explained by intermolecular forces (hydrogen bonding) between the water/glycol and shale matrix. The shale matrix has a high propensity to adsorb water which further leads to the swelling and ultimately to the dispersion in the shale matrix. The water molecules in the shale matrix form hydrogen bonds with the aluminate and silicate groups and when glycols interact with the shale matrix it is believed that glycols and poly glycols beak down the hydrogen bonding of water molecules with aluminates and silicates of the clay minerals [97]. The PEG molecules compete with water molecules in the interlayer spaces and attach with the aluminates and silicates of clay minerals through hydrogen bonding and prevent the further interaction of water with clay minerals [98]. Polyethylene glycol with a molecular weight less than 1000 is used as shale inhibitor in the water-based drilling fluid. Freshwater showed zero percent shale recovery in the shale dispersion experiment while polyethylene glycol systems only show a 20% shale recovery. On the other hand, the PHPA/KCl drilling fluid system showed 50% and the glycol/PHPA/KCl system showed an 80% recovery in the shale sample. The shale hardening test with glycol-based drilling fluid showed that the shale matrix becomes harder after interacting with the glycol-based fluid compared to the original shale sample which behaves as a softer shale sample [96]. An effective shale inhibition system was produced by the combination of salt (KCl) and glycol in the water-based drilling fluid. Both salt and glycol adsorb on the clay surfaces which minimizes the interaction of the water and shale matrix resulting in reduced clay swelling. The water in the hydration of potassium cations in the shale is replaced with the glycol which has larger molecules than water and adsorbs at multiple positions with shale samples through hydrogen bonding. The glycol adsorption on the surfaces of clay minerals with aluminates and silicates was also observed and resulted in the hardening of the shale sample. The inhibition of shale is not only due to the glycol but also the presence of salt (KCl) plays an important role to enhance shale inhibition [96]. Similarly, another study of 600 molecular weight polyethylene glycol showed that a 3% PEG solution offers better inhibition properties compared to water. Also, the addition of 7% KCl salt into a 3% PEG solution showed improved inhibition properties but very similar to the inhibition properties of a 7% KCl solution. In the presence of salt (KCl) solution, PEG shows little impact on inhibition properties. Particle size distribution is another technique to determine the inhibition characteristics of PEG and salt solutions. The higher particle size distribution indicates better inhibition characteristics for a shale inhibitor. The potassium chloride solution with 0.5% showed 21.41 μm while the addition of 3% PEG to the system increased the particles size distribution to 31.57 μm. This indicates that a lower concentration of salt and PEG has a synergic effect on shale inhibition. The copolymer of ethylene oxide with ethylene glycol (PG-1) and propylene oxide with ethylene glycol (PG-2) is also used to determine the capability of shale inhibition. The copolymer (PG-1) measured 45.03 μm while (PG-2) measured a 51.52 μm particle size distribution and this greater particle size distribution was attributed to enhanced aggregation due to the hydrophobic contents in the copolymer. The author concludes that copolymers having hydrophobic contents showed enhanced aggregation capabilities compared to the PEG only. Significantly, particle size

Several inhibitors have been developed in the last few decades to address shale swelling. Potassium chloride (KCl) is one of the earliest known shale inhibitors that has been used in a concentration ranging from 2% to 20%. However, water-based drilling fluids containing potassium chloride (KCl) concentration more than 1 wt% severely affect the microorganisms and have failed the mysid-shrimp bioassay test [89]. Therefore, water-based drilling fluids having potassium ions are less often considered for offshore deep-water drilling operations due to the toxicity of potassium ions for marine life. Potassium chloride was later used in combination with partially hydrolyzed polyacrylamide (PHPA) in the1960s to minimize clay swelling in water-based drilling fluids. The presence of PHPA in water-based drilling fluids serves as an inhibiting agent by forming a protective layer on the clay and preventing the interaction of water with the clay minerals. The calcium chloride-based drilling fluid was also used for the inhibition of shale formation by encapsulation and ion exchange mechanisms. The presence of calcium ions (Ca2+) in the drilling fluid displaces the monovalent cations from interlayers of clay and prevents the swelling of clay platelets. The polymer present in the calcium chloride-based drilling fluid shows an affinity for clay minerals and consequently, physical adsorption (encapsulation) of polymer on the surfaces of clay minerals reduces the water activity in shale formations. The presence of calcium ions helps in the encapsulation of polymer on clay minerals [90]. The dispersions and swelling of clay can be effectively inhibited either by intercalating the interlayers of clay minerals with inhibiting agents or covering the shale formation with high molecular weight polymers and preventing the interaction of water with reactive shale formations. In the last few years, several shale inhibitors have been developed. These inhibitors can be polymeric inhibitors, ionic liquids, and surfactants. The following section discusses the recent progress and advancement in developing shale inhibitors. 5.1. Polymeric inhibitors Polymers are used as water-based drilling fluid additives and perform various functions in the drilling process. Polymers are added to control the viscosity, suspension ability of a fluid, and inhibition of shale formations [91,92]. The viscoelastic properties such as yield stress and linear viscoelastic range of polymer-based drilling fluid is an important characteristic that describe shale cutting transport capacity from downhole to surface of well and well cleaning efficiency [19]. Polymeric shale inhibitors not only enhance the inhibition properties of drilling fluids but also modify the rheological and filtration properties [87,93,94]. In this section, inhibition properties of polymer additives in drilling fluids will be discussed in detail. Polymer-based inhibitors are used to prevent clay swelling in water-based drilling fluids. Inhibition properties are mainly related to the concentration, structure, and charge of polymeric additives in the drilling fluids. Polymer-based inhibitors consist mainly of three categories, namely anionic polymers, cationic polymers, and non-ionic polymers. Each class of polymer inhibitors has a certain capacity to inhibit clay swelling based on the type of clay minerals in the wellbore. 5.1.1. Non-ionic polymers and derivatives Non-ionic polymers including, mainly, polypropylene oxide (PPO), polyethylene glycol (PEG) [95], and their derivatives with nanoparticles are also used for shale inhibition applications. Polyglycols are considered as effective shale inhibitors in water-based drilling fluid systems and are replacing the use of oil-based drilling muds due to the superior inhibition properties. The extraordinary benefits of using glycol as shale inhibitor include good lubrication, low cost, easy handling, and environmental friendliness. Various experimental techniques are employed (shale dispersion and shale swelling) to study the shale inhibition due to shale hardening. Shale hardening is a process in 194

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distribution should be the criteria to determine the inhibition capacity of shale inhibitors rather than conventionally used linear swelling experiments [99]. A recent approach has been adopted to introduce the hydrophobic groups in non-ionic polymers (polyethylene glycols) to enhance the inhibition performance of shale inhibitors. For this purpose, hydrophobically modified polyethylene glycols were synthesized using different synthesis routes and the influence of lipophilic (aliphatic groups) units and hydrophilic units (ethylene oxide units) on the performance of inhibition characteristics were determined. The basic mechanism that explains the inhibition of shales is that modified and unmodified polyethylene glycols penetrate and adsorbs into the interlayers of smectite enriched clays and prevent the swelling of shales. However, the hydrophobically modified polyethylene glycol has water repellent groups attached to its molecules, which prevents the seeping of water into the shale surface and swelling by making a preventive barrier against the shale matrix. The adsorption of non-ionic polymers on the surface of shale is a very important phenomenon and is affected by the structure, the presence of salt (KCl, NaCl, LiCl) and hydrophobic contents in the polymer structure. There are a few studies that explain the shale cutting recovery and stability of shale formations using these polymers in the literature [100,101]. De Souza et al. have synthesized hydrophobically modified polyethylene glycol (diesters of PEG’s) by reacting 400 g/mol molecular weight PEG. The inhibition performance of synthesized hydrophobic molecules such as PEG400C2 and PEG400C12 was compared to the PEG400 molecules by adsorption and by shale recovery experiments. The adsorption measurements were taken for different molecular weights of PEG and the adsorption capacity on clay surface was assessed. The adsorption isotherm experiment showed that the adsorbed amount of PEG on bentonite increases with increases of the molar mass of PEG from 400 to 1500 g/mol. But higher molecules of PEG adopt random conformation and decrease the polarity of polymer chains which adsorb at the clay surfaces randomly with tails and loops. This random structure of PEG at higher molar mass and abnormal adsorption on the clay surface brings the clay platelets together by bridging with each other and the PEG adsorption amount on the clay surface is reduced. To compare the adsorption performance of PEG400 with hydrophobic PEG’s, adsorption isotherm experiments were performed. PEG400C2 showed similar adsorption to the adsorption of PEG400 because the former has OH terminal hydroxyl group attached in the structure that can be used for hydrogen bonding. The PEG400 also has no hydroxyl group in the structure but the adsorption takes place due to the ethylene oxide group in the structure. The structure of PEG400C12 was considered superior for adsorption of clay surfaces compared to all other structures due to the presence of long aliphatic chains which successfully adsorb on the clay surface and form additional layers by hydrophobic groups and protect the clay from interacting with water. These long chains are kept on the outside of clay surface interlayers and prevent the water from interacting with clay minerals [35]. Ferreira et al. have introduced hyperbranched poly glycols with remarkable structures which are obtained from glycidol or glycol carbonate are considered superior shale inhibitors. Experimental studies show that hyperbranched structures have superior inhibition properties compared to the linear structures of polyethylene glycol. The inhibition of reactive shale formations can be done by enhancing the hydrophobicity of hyperbranched structures of poly glycols [104]. The synthesis of hyperbranched polyglycerol partially hydrophobized was prepared by reacting the polyglycerol and dodecyl tetradecyl glycidyl ether in different molar ratios 1:1, 1:2 and 1:4 and named HPG11, HPG12, and HPG14, respectively. The synthesis route of final hyperbranched polyglycerol partially hydrophobized is mentioned below in Figs. 6 and 7. Hot rolling dispersion experiments were carried out with HPG11 and HPG12 and recovery of the shale sample was similar to the

recovery measured by poly-DADMAC, which is a commercially used shale inhibitor. The shale recovery of HPG systems was higher compared to the PEG (400 g/mol) fluid system. The HPG systems show superior inhibition performance in the presence of KCl salt probably due to the formation of complex structures between the polymer and potassium cation. The complex structure favors the adsorption of polymer on negatively charged layers of shale and similar results of polymer adsorption have been mentioned in the literature [102,103]. The hot rolling dispersion experiments showed that partially hydrophobized molecules of HPG are considered superior inhibitors compared to the polyglycerols due to the lower solubility of HPG in water compared to the polyglycerols and increased adsorption on negatively charged shale surfaces. The HPG solubility in the aqueous phase and adsorption mechanism of the negatively charged clay surface is explained by adsorption isotherms. It is believed that HPG11 and HPG 12 have similar inhibition characteristics while HPG12 follows an abnormal trend which suggests that inhibition characteristics depend on the degree of hydrophobic contents in the non-ionic polymer systems. The aqueous systems containing HPG11 and HPG12 and KCl salt showed superior shale recovery results of up to 80% and these interesting results suggest that its applications can be applied to real field applications. The bentonite inhibition test was performed with HPG14 and inhibition results showed that it has maximum inhibition properties compared to all other nonionic polymer systems even in the absence of KCl salt. The mechanism that explains the best inhibition performance of HPG14 is that when it was mixed with bentonite powder and after aging of the sample, bentonite platelets get flocculated with the molecules of HPG14 and these flocculates remain intact even after the vigorous mixing with the mixer. These flocculate prevent bentonite from making clay swell and in the presence of KCl salt these flocculate were not observed [104]. 5.1.2. Ionic polymers Ionic polymers and their derivatives with structural modifications are considered superior shale inhibitors for the inhibition of shale reservoirs. Ionic polymers are further classified as cationic polymers and anionic polymers, and both are considered effective shale inhibitors in the formulations of water-based drilling fluids. There are different inhibition mechanisms of polymeric based shale inhibitors which involve the adsorption of polymers on the surface of shale and the formation of hydrogen bonding of shale inhibitors with the surface of shale. The prime purpose of shale inhibition using ionic polymeric inhibitors is to prevent the dispersion of drilled cuttings and to protect the borehole surface. In the following section, two different classes of shale inhibitors will be discussed. First, acrylamide-based polymers and its derivatives (copolymers and terpolymer); second, amine-based shale inhibitors with their properties and their effect on shale inhibition. 5.1.2.1. Acrylamide based polymers. Polyacrylamide (PAM) and partially hydrolyzed polyacrylamide (HPAM) are considered potential additives for water-based drilling fluids. They have long chain molecules which adsorb on the surface of clays and are specifically used to prevent the hydration and dispersion of clays in the wellbore [79–81]. In recent decades, many water-soluble polymers have been used for shale stabilization and to inhibit hydration and swelling. But most of the polymers have less ability to stabilize shale under high salinity and in high-temperature environments [105,106]. Several water-soluble copolymers are employed in the drilling fluid industry to modify drilling fluid rheological, filtration, and shale inhibition properties [108–112]. Recently, a copolymer was synthesized using acrylamide (AM), N,N-diallyl benzylamine (NAPA), acrylic acid (AA), and 2-(acrylamide)-2-methylpropane-1-sulfonic acid (AMPS) through a radical copolymerization technique and called as PANAA. This copolymer has structural diversity due to the presence of carboxyl groups, heterocycles and benzene rings which impart high temperature and high salinity tolerance. The structure of PANAA copolymer is given 195

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Fig. 6. Synthesis route for hyperbranched polyglycerol [104]. ©Elsevier. Reproduced by permission of Elsevier.

in Fig. 8. The inhibition properties of PANAA were determined by measuring the interlayer spacing of sodium montmorillonite clay. The neat MMT clay showed 19.04 Å and in the presence of (5000 mg/L) of the PANAA copolymer, the interlayer spacing was reduced to 18.74 Å. However, the pronounced effect on the reduction of interlayer spacing was observed with the addition of 3% KCl in the solution and interlayer spacing was reduced from 18.74 Å to 15.65 Å. The superior viscosity of PANAA at higher concentrations of salt also indicate its salt tolerance. The drilling of deepwater oil and gas wells with a high molecular weight encapsulator addresses the thickening problem of drilling fluid at low temperature, where it is difficult to control the fluid loses and bottom hole pressure. These problems can be avoided by using a low molecular weight encapsulator in the water-based drilling fluid rather than conventional shale encapsulators. Recently, a zwitterionic terpolymer P(AM-DMC-AMPS) with monomers containing acrylamide,

methacrylate ethyl trimethyl ammonium chloride, and 2-acrylamido-2methylpropane sulfonic acid was synthesized via the solution polymerization technique. The terpolymer was used as low molecular weight encapsulator to study the swelling inhibition properties of a shale sample. The molecular structure of terpolymer is shown in Fig. 9. The efficient inhibition capacity of the low molecular weight encapsulator was due to the strong inhibition capacity compared to the conventionally used encapsulators and it reduced the hydration and dispersion of shale. The results also show that low molecular weight encapsulator was compatible in water-based drilling fluids and the recovery of shale increased with the encapsulator compared to the conventionally used shale encapsulators. The swelling rate of the shale sample in fresh water was approximately 41% indicating a high hydration capacity which results in severe wellbore instability problems. The presence of a low molecular encapsulator significantly reduced the

Fig. 7. Synthesis route for hyperbranched polyglycerol hydrophobized [104]. ©Elsevier. Reproduced by permission of Elsevier.

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Fig. 8. Acrylamide sulfonate copolymer PANAA [107]. ©ACS Publications. Reproduced by permission of ACS Publications.

effects and surface tension [113]. The polymer microsphere emulsion showed superior temperature and salt resistance at the severe conditions of the bottom hole. Pore plugging of the shale sample was observed analytically by taking SEM images before and after immersing the shale sample in a polymer microsphere emulsion as shown in Fig. 11. A natural shale sample has many micropores and nanopores and cracks, but after interacting the shale sample with the fluid containing the polymer microsphere emulsion, the pores and cracks became tightly plugged with the PME, which greatly reduced the permeability of the shale sample. This was also confirmed using a pore pressure transmission test in which the pressure transmission rate was decreased with an increase in time. These results indicate the effective plugging capacity of PME in the pores and cracks of a shale sample. The maximum shale recovery of 88.4% was observed with a 2% concentration of PME. The contact angle substantially increased with the increase in the concentration of PME in water-based drilling fluid thereby making the shale surface hydrophobic. The hydrophobic shale surface repels water and shows a little affinity for water. The shale formation contains a lot of micro- and nanopores with fractures and cracks through which water molecules seep in resulting in shale hydration and swelling. The schematic diagram of the wellbore stability mechanism of PME is shown in Fig. 12. The polymer microspheres were squeezed into these pores and cracks under the capillary pressure and drilling differential pressure which resulted in the dense physical plugging decreasing the pore pressure transmission and permeability in favor of shale stability. This physical plugging of the shale surface with PME makes the surface more hydrophobic in nature which prevents the interactions of water with shale and increases the shale inhibition performance [114,115]. For reactive shale formations, graft copolymers have recently been employed as additives for water-based drilling fluids to reduce shale hydration and swelling. Graft copolymers have many applications in drilling oil and gas wells. They are soluble in water, provide resistance to enzyme environments, and are mechanically and thermally stable in high-temperature drilling applications. Polyacrylamide/diallyl dimethyl ammonium chloride-grafted-gum acacia copolymer was synthesized using the free radical polymerization technique for the inhibition of troublesome shale hydration and swelling. Gum acacia is a biopolymer and consists of many species such as arabino galacto protein, polysaccharide and proteins which have diverse industrial applications. For water-based drilling fluid applications, gum acacia is often provided for pH stability, gelling characteristics, low viscosity, water solubility and non-toxicity [116,117]. The grafting reaction between gum acacia and the copolymer of polyacrylamide and diallyl dimethyl ammonium chloride resulted in grafted polymer which has special properties and can be used as a water-based drilling fluid additive, rheology control modifier, fluid loss control agent and shale stabilizer. The shale recovery test was performed with 0.9 w/v% of the grafted copolymer in the water-based drilling fluid and shale recovery was 96.4 wt%. However, the shale recovery was only 86.6 wt% with 0.9 w/ v% of PHPA concentration. The overall shale recovery results prove that synthesized grafted copolymer provides superior shale recovery compared to the conventionally used shale stabilizer PHPA. The slake

Fig. 9. Structure of terpolymer P(AM-DMC-AMPS) [63]. Reproduced according to terms of Creative Commons Attribution 4.0 International License (http:// creativecommons.org/licenses/by/4.0/).

swelling rate of shale compared to fresh water. It is believed that the encapsulator adsorbs on the surface of the wellbore and wraps the surface of shale particles through hydrogen bonding and electrostatic force of attractions which reduce the invasion of water and maintain the integrity of the wellbore. The superior shale inhibition and rheological properties of water-based drilling fluids containing low molecular weight encapsulators endorse its potential use for deepwater drilling compared to the use of conventionally available encapsulators. Along with superior shale inhibition and improved rheological properties at low temperatures, low molecular weight encapsulators also showed good salt tolerance up to 10–20% concentrations of sodium chloride [63]. For water sensitive shale formations, a copolymer of carboxymethyl and polyacrylamide was synthesized via the free radical polymerization technique and the resultant carboxymethyl-grafted-polyacrylamide copolymer exhibited superior inhibition properties. With an increase in the concentration of grafted copolymer from 0.3% to 0.8%, the shale recovery was improved from 68% to 89.4%. The enhanced inhibition properties of the copolymer are due to the pronounced encapsulation effect on the shale sample caused by the adsorption of the copolymer on the surface of shale making a thin film which restricts the migration of water in the shale matrix [44]. The demand for nanomaterials has widely increased to enhance oil and gas drilling applications. Polymer microsphere emulsion (PME) synthesized through emulsion polymerization can be employed as highperformance shale stabilizer for water-based drilling fluids. The schematic diagram of emulsion polymerization is shown in Fig. 10. The monomers 2-acrylamide-2-methylpropane sulfonic acid (AMPS), nbutyl acrylate (BA) and styrene (St) were used to synthesize the microsphere emulsion in which AMPS acts as hydrophilic moiety to enhance the dispersion of the polymer in water-based drilling fluids while styrene and n-butyl acrylate are hydrophobic moieties used to stabilize the shale formations. The polymer microsphere emulsion stability was enhanced with emulsifiers which are also used to reduce capillary 197

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Fig. 10. Schematic diagram of the polymer microsphere emulsion polymerization system [90]. Open access article published by The Royal Society of Chemistry.

durability index in the PHPA system was 53% at 0.9 w/v% concentration, while in the presence of the grafted copolymer system, the slake durability index was increased to 81% at 0.9 w/v% concentration of grafted copolymer. These results prove that grafted copolymer has superior inhibition properties compared to the PHPA system when used in the water-based drilling fluid. The mechanism that protects the shale formation explains that the hydrated sodium ions are replaced by ammonium ions which are used to neutralize the negatively charged surface of clay and form a protective layer to inhibit the hydration and swelling of shale [118–121]. The shale formations which contain high amounts of clay required special attention for the inhibition of swelling and to maintain the integrity of the wellbore. For this purpose, a special polyacrylamide/clay nanocomposite was reported that was synthesized via the free radical polymerization technique. The shale recovery experiment was performed and compared with the base fluid (PHPA system). The recovery of shale in the PHPA system was less at all concentrations compared to the nanocomposite system. The recovery of shale was observed to be 93.2% at 0.8% concentration of the nanocomposite system. The presence of nanocomposites in the drilling fluid system prevents the disintegration of the shale sample by making a thin protective nanocomposite layer. The thin nanocomposite layer attached to the surface

of shale through hydrogen bonding and the electrostatic force of attraction. This protective layer prevents the interaction of water with shale making the shale sample more stable towards dispersion and swelling [9]. In summary, various acrylamide-based copolymers have been reported in the literature and showed better properties compared to the conventional partially hydrolyzed polyacrylamide. The improvement was achieved by incorporating monomers that can reduce the shale swelling and improve disintegration of shale. 5.1.2.2. Polyamines. Nitrogen-based compounds and their derivatives have been used for the inhibition of shale for many years. The simplest nitrogen-based inhibitor is ammonium chloride. Properties of aminebased compounds as shale inhibitors have been reported in the literature [120,122,123]. The previously used potassium chloride shale inhibitor had many disadvantages such as toxicity in marine environments and the potassium ion causing swelling in kaolinite clay under certain conditions leading to the instability of the wellbore. To alleviate all the disadvantages of salt, researchers have found organic cations which behave like potassium ions for shale inhibition and then amine-based compounds were evaluated for the inhibition of shale [124]. In the last few years, several amine-based compounds were

Fig. 11. SEM images of shale core samples before and after interacting with the polymer microsphere emulsion [90]. Open access article published by The Royal Society of Chemistry.

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Fig. 12. The schematic diagram of a wellbore stability mechanism by PME [90]. Open access article published by The Royal Society of Chemistry.

suggested that the montmorillonite showed the highest rate of water adsorption due to its hydrophilic nature. The treatment of montmorillonite with polyether amines changes the hydrophilicity of clay which affects the water adsorption performance. The minimum water adsorption rate was observed for PEA-3 which makes the clay surface less hydrophilic. The polyether amine interactions with the clay surface are shown in Fig. 14. The presence of terminal amines attached with the clay surface and polypropylene oxide polymer chains makes the clay surface less hydrophilic and inhibits the hydration and swelling of clay. The polyether amine (PEA-3) showed superior inhibition performance compared to all other compounds. The PEA-3 interacts with the clay surface through hydrogen bonding; electrostatic adsorption, which resulted in the monolayer arrangement, and a hydrophobic shielding effect; making it the most suitable candidate of the polyether amines [71]. The polyamido amines substituted with the hydrophobic group are considered as additives in water-based drilling fluid for the inhibition of shale hydration and swelling. Poly(oxypropylene) amidoamines were synthesized for the inhibition of shale swelling and hydration by condensation reactions of diacids and polyoxypropylene diamines. The structure of poly(oxypropylene) amidoamine is shown in Fig. 15. XRD analysis suggested that interlayer distance increased from 1.21 nm to 1.43 nm at the 0.5 (m/v.%) the concentration of POAA. Further increases in the concentration did not increase the intercalating effect on the interlayer distance which indicates a monolayer arrangement of POAA between the interlayer. Additionally, the use of high molecular weight POAA further increased the interlayer distance. The shale recovery experiment showed that the increasing concentration resulted in an increase in shale recovery and the addition of KCl further enhanced the recovery of shale. The interactions such as hydrogen bonding, electrostatic and van der Waal forces between the clay surface and POAA compounds resulted in superior inhibition performance [126]. Another category of shale inhibitor is polyoxyalkyleneamine (POAM) which is used for the inhibition of sensitive shale formations. Various inhibition experiments were carried out with sodium montmorillonite to study the inhibition performance of POAM. The use of 2% POAM in the water-based drilling fluid enhanced the shale recovery and it had superior results for the suppressing of clay hydration and swelling in the harsh drilling environment. The polyoxyalkyleneamine has many advantages over conventionally used shale inhibitors such as compatibility with other water-based drilling fluid additives and low toxicity for a marine drilling environment [127]. A recent study related to the compound of multiple primary amines as shale inhibitors was carried out and results were compared with the diamines. Low molecular weight branched polyethyleneimine (BPEI) and hexamethylendiamine (HMDA) were utilized to evaluate and compare the inhibition performance of inhibitors. The chemical structures of BPEI and HMDA are mentioned in the following Fig. 16. The

Fig. 13. Chemical structures of different polyether amines [71]. ©Elsevier. Reproduced by permission of Elsevier.

studied as shale inhibitors such as polyamine acid, lipophilic polymeric amines, hexamethylenediamine, poly-hydroxylated alkyl ammonium salt and dendritic amines [125]. Polyether amines have attracted great interest as shale inhibitors in water-based drilling fluids due to their efficient shale inhibition properties. The interactions between clay particles and polyether amines depend on several factors such as the size of molecular chains, molecular weight, and a number of amine groups in the structure of polyether amines. The molecular structures of various amines are mentioned in Fig. 13. The hot rolling dispersion test was carried out on several polyether amines suggests that PEA-3 showed the maximum shale recovery at approximately 75.76%, while PEA-6 showed the minimum recovery of the shale sample. The water adsorption test 199

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Fig. 14. Schematic diagram of clay swelling and PEA-3 inhibition mechanism [71]. ©Elsevier. Reproduced by permission of Elsevier.

chemical structure of BPEI shows that it is a large hyperbranched structure with multiple primary amines attached at the end of molecular chains and high solubility in water. The primary amine attached at the ends has the ability to form interactions (hydrogen bonding) with the clay surface. Furthermore, the compatibility of BPEI and other components of drilling fluid, superior inhibition performance, and high viscosity makes it a preferable candidate for water-based drilling fluids. The design criteria for cationic shale inhibitors to inhibit the swelling of clays has been reported in the literature. According to this design criteria, the cationic shale inhibitor should be soluble in water and can replace the interlayer cations of clay. The cationic shale inhibitor should have a cationic group in the structure or primary diamines and a long chain alkyl group or a hydrophobic group that can form a monolayer on the surface of clay and protect the clays from hydration and swelling [128]. The linear expansivity of shale inhibitors such as potassium chloride, choline chloride, polyether amine, HMDA, and BPEI were evaluated over periods of 2 and 16 h. The results showed that BPEI had the lowest linear expansivity which predicts a better inhibition performance. The interlayer spacing was measured with HMDA and BPEI and it was observed that interlayer spacing decreased sharply in the presence of alkyl amine inhibitors; (HMDA and BPEI) however, further increases in the concentration had no effect on interlayer spacing which indicates the formation of a monolayer of inhibitors on the clay surface. The presence of the hydrophobic group repels the water in the interlayers and protects them from hydration and swelling [72]. The hyperbranched polymer was recently introduced as an additive in water-based drilling fluid for the inhibition of shale from hydration and swelling. Amine-terminated hyperbranched polymer (HBP-NH2) was synthesized by the condensation reaction of diamines. The chemical structure of the hyperbranched polymer is shown in Fig. 17. The effectiveness of hyperbranched amine terminated polymer was determined with different experimental techniques such as the hot rolling dispersion test and linear swelling experiments. Most of the available shale inhibitors are amine-based inhibitors and mainly diamines in

Fig. 16. Chemical structures of 1,6-hexmethylenediamine and branched polyethyleneimine [72]. ©Elsevier. Reproduced by permission of Elsevier.

Fig. 17. Chemical structure of hyperbranched-NH2 [133]. ©John Wiley & Sons. Reproduced by permission of John Wiley & Sons.

Fig. 15. Chemical structure of POAA [126]. ©Elsevier. Reproduced by permission of Elsevier.

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Fig. 18. Adsorption mechanism of HBP-NH2 with clay [133]. ©John Wiley & Sons. Reproduced by permission of John Wiley & Sons.

which amine groups are attached at the end of linear molecular chains. There are many shortcomings of conventionally available amines such as the linearity of molecular structure, the number of amine groups in the molecule, and the fact that adsorption of linear amine inhibitors on the clay surface is irregular and uneven with few available adsorption sites. During drilling operations at high turbulence and temperature, the adsorption of linear diamines on the clay surface is considered weak. Whereas, hyperbranched amine terminated polymer has quasispherical structure and amine groups are attached at the terminal ends which defines the chemical properties and effectiveness of the inhibition properties of the hyperbranched polymer molecule [129–132]. The linear expansion rate of shale was determined in the presence of hyperbranched amine terminated polymer and it was observed that the expansion rate decreased with an increase in concentration. The minimum expansion rate was observed to be 11.42% at 3 wt% polymer

concentrations. It was observed that the minimum expansion rate was for amine terminated hyperbranched polymer compared to all other shale inhibitors. The shale recovery experiment showed that increasing concentrations of hyperbranched polymer increased the shale recovery and the maximum recovery of shale (68.54%) was observed at 5 wt% concentration of HBP-NH2. The adsorption of hyperbranched amine terminated polymer can be observed in Fig. 18. Unlike linear diamines, the adsorption of the hyperbranched polymer can occur at high-temperature environments and turbulent environments. This adsorption was due to the highly branched structure with amine terminated ends which attached with the clay surface and resulted in protection from shale hydration and swelling [133]. Amine-terminated dendrimer demand has been increased in the drilling industry as an additive to water-based drilling fluids due to the peculiar properties and their unique hyperbranched structure. Recently,

Fig. 19. Structure of PAMAM dendrimer (G3) [70]. ©Elsevier. Reproduced by permission of Elsevier. 201

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Fig. 20. The chemical interactions of bentonite and PAMAM dendrimers [70]. ©Elsevier. Reproduced by permission of Elsevier.

research that if the zeta potential of dispersion ranges from −16 to −30 mV, the dispersion is considered weak. If the zeta potential is in the range of −10 to −15 mV, then the particles of dispersion can easily bind together in the presence of an inhibitor. It can be concluded from the above discussion, that the PAMAM dendrimers, PEA and KCl can significantly reduce the zeta potential and inhibit the swelling of clay [142]. The chemical interactions of bentonite platelets and PAMAM dendrimers are presented in Fig. 20. The presence of low concentrations of PAMAM dendrimers forms a monolayer between the platelets of bentonite and results in an intercalated structure. When the concentration of PAMAM dendrimer is increased, the interlayer distance of bentonite platelets increases due to the formation of a bilayer of dendrimer and the adsorption of the PAMAM dendrimer at multiple positions between the negatively charged bentonite platelets and protonated dendrimers. This removes the water from interlayers of bentonite for a superior inhibition performance. The decrease in the pH value resulted in the enhanced protonation of amine groups of dendrimers which increased the interactions between bentonite platelets and dendrimers. The increased interaction resulted in a decrease of interlayer spacing and enhanced the inhibition performance of PAMAM dendrimers [70]. Alkyl amines have different numbers of primary amines attached with the alkyl chains of different lengths. The structures of various alkyl amines are presented in Fig. 21. The rate of adsorption significantly increased with the increase in the number of primary amines in the shale inhibitor. The alkyl amine interacted with the clay particles and formed a monolayer on the platelets of clay resulting in an intercalated structure. The alkyl amine replaces the interlayer replaceable cations from the interlayers of clay and an embedded structure was formed which repels the water molecules and protects the clay from swelling and hydration. The linear expansivity of shale was determined using different alkyl amines to investigate the inhibition performance at 2 and 16 h. The

various studies have shown the unique application of dendrimers in oilfield chemistry [125,134–140]. Amanullah et al. have developed a high-performance drilling fluid which uses dendrimers as additives for challenging drilling applications [125]. In a study by Zhong et al., five different amine-terminated polyamidoamine (PAMAM) dendrimers from G0 to G5 were evaluated by various experimental techniques; the chemical structure of a dendrimer is shown in Fig. 19. Shale recovery experiments carried out in the presence of various PAMAM dendrimers, KCl and polyether amine at different pH values showed that the shale recovery with the control sample was low while the shale recovery with PAMAM dendrimers, PEA and KCl was comparatively high. The high recovery of the shale sample depicts less dispersion of shale and enhanced inhibition properties of shale inhibitors. The shale recovery was determined at a pH value of 11 and the maximum shale recovery was observed for the G5 PAMAM dendrimer compared to all other shale inhibitors. The shale recovery was further increased for all the shale inhibitors with a decrease of pH value and the G5 dendrimer still shows the maximum shale recovery compare to all other shale inhibitors. The zeta potential of clay particles was determined in order to study the effect of shale inhibitors on the electro kinetic properties of clay dispersions at two different pH values. According to Garea et al., the colloidal dispersion with a zeta potential value of 30 mV is considered as a stable dispersion [141]. Colloidal dispersion with clay particles having high negative values of zeta potential is prone to swelling and dispersion in an aqueous medium. The zeta potential of bentonite clay particles is reported as −39 mV which indicates a stable dispersion of clay particles. The addition of PAMAM dendrimers decreased the zeta potential of clay dispersion from −39 mV to −22.6 mV. For PEA the zeta potential was reduced to −18.7 mV and for KCl zeta the potential was further decreased to −11.5 mV. Mohan and Fogler have reported in the literature that a 20% reduction in charge on the layers of clay can completely inhibit the swelling of clay [75]. Riddick has stated in his 202

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Fig. 21. The chemical structures of alkyl amines [143]. ©Elsevier. Reproduced by permission of Elsevier.

lower expansion rate indicates superior shale inhibitor performance. The linear expansivity of shale was significantly reduced in the presence of alkyl amines at 2 and 16 h compared to fresh water. The linear expansivity rapidly decreased with increasing numbers of alkyl amines indicating better performance. The microstructure of hydrated clay was investigated with and without the presence of alkyl amines using SEM analysis as shown in Fig. 22. The SEM images indicate an enhanced agglomerate of clay in the presence of alkyl amines as compared to the simple hydrated bentonite. The surface structure and edge curl phenomenon were more prominent in the alkyl amine complexes compared to the hydrated bentonite. The clay and PD inhibitor complex showed the presence of globule structures in the SEM photograph and the by increasing the number of primary amines in the structure it resulted in a well-ordered layer structure of clay. The alkyl amines having multiple

primary amine groups are promising shale inhibitors for water-based drilling fluids [143]. Polyethyleneimine (PEI) is considered as an environmentally friendly shale inhibitor. PEI is an alkaline water-soluble polymer containing large numbers of cationic groups in its structure. Due to the presence of many nitrogen atoms in this polymer, it has the ability to form hydrogen bonds with other electronegative atoms. PEI has many industrial and engineering applications such as in bioengineering, the oil and water treatment industry, and the coating industry [144–155]. The inhibition mechanism can be explained in such a way that interlayer cations are replaced with the PEI molecules which repel the water molecules to migrate to the interlayer spacing. The amino groups in the PEI make hydrogen bonds with the hydroxyl groups of clay and result in the adsorption of PEI on the clay surface. The electrostatic interactions

Fig. 22. SEM photographs with hydrated sodium bentonite and alkyl amines (a) hydrated sodium bentonite (b) sodium bentonite + PD inhibitor (c) sodium bentonite + APD inhibitor (d) sodium bentonite + BAPD inhibitor [143]. ©Elsevier. Reproduced by permission of Elsevier. 203

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Fig. 23. The schematic mechanism for the inhibition of PEI with montmorillonite [156]. ©Elsevier. Reproduced by permission of Elsevier.

and adsorption of PEI form an intercalated structure of clay. The mechanism of PEI adsorption and the formation of the intercalated structure is shown in Fig. 23. The shale recovery was minimal in the presence of fresh water while, except for PEI1800, shale recovery was significantly increased in the presence of increasing molecular weight PEI. The higher the recovery of shale for a specific shale inhibitor, the better will be its inhibition performance. The increasing molecular weight of PEI resulted in the decrease of linear swelling of montmorillonite pellet and lowest swelling was observed with PEI70000 shale inhibitor [156]. Polyether diamine (PEDA) is also used as an additive in water-based drilling fluids for the inhibition of shale swelling and hydration. The polyether diamines are considered remarkable shale inhibitors due to their excellent inhibition capacity, low molecular weight and less toxicity for drilling fluid applications including rheological modifiers, dispersants and fluid loss modifying agents [157–160]. X-ray diffraction analysis showed that the interlayer spacing of montmorillonite at 0.5% concentration of PEDA increased from 1.21 nm to 1.36 nm indicating the intercalation of PEDA. The further increase in the concentration of diamines had no increased effect on the interlayer spacing which indicates the formation of a monolayer on the platelets of montmorillonite and with increasing concentrations of PEDA, the interlayer space remains unchanged. In addition, the slope for the PEDA hot rolled cuttings was high compared to the KCl rolled cutting sample indicating a higher bulk hardness and superior inhibition performance. For water and KCl rolled cutting samples, the plateau regions were shown by the extrusion of shale cuttings and the softening of the shale sample. The decrease in the pH of PDEA resulted in an increase in the slope of bulk hardness curves which indicates that hardness and inhibition performance increased with lowering of the pH of PDEA containing drilling fluid during the hot rolling experiment [94].

stability of clay suspensions [164]. The adsorption of inhibitors on the clay surfaces with hydrophobic groups results in a shielding effect. The shielding effect of hydrophobic groups result in the decrease in the thickness of the electrical double layer and have restricted movements compared to the small particles [165–168]. Interactions of the amine group with clay particles determine the inhibition capacity of amines and are mainly affected by hydrogen bonding, static electric interactions and the hydrophobic shielding effect of inhibitors. Shale inhibition takes place by the adsorption of protonated cationic amine groups followed by the neutralization of the negative charge on the clay particles resulting in the formation of monolayer arrangement in the interlayers of clay particles. The interactions among clay particles and amine group result in the compression of a diffuse double layer of clay particles which results in the formation of flocculated clay particles. Low molecular weight 4,4-methylenebis-cyclohexanamine (MBCA) showed good inhibition characteristics for sodium bentonite [169]. The sodium bentonite dispersion in an aqueous medium showed a −39.9mV zeta potential which represents suspension stability. Zeta potential values for MBCA and sodium bentonite suspension showed a decreasing trend and dropped to −20.8 mV with the increasing concentration up to 2 w/v% of inhibitors. The presence of MBCA in an aqueous solution of sodium bentonite makes the surface more hydrophobic. Clay hydration and swelling could be completely inhibited if the negative charge on the clay minerals is reduced by 20% [75]. A zeta potential value between −30 mV and −16 mV indicates a weak dispersion. The shale inhibitive properties of MBCA for montmorillonite using contact angle measurements also suggests their good inhibition properties. The water droplet made an angle of 29.8 for montmorillonite film which shows the hydrophilicity of clay minerals (montmorillonite). The increasing concentration of MBCA in the montmorillonite showed that the contact angle increased up to 86.2. The increase in the contact angle suggests that the wettability of the clay layer decreased, becoming more and more hydrophobic in nature. The increased hydrophobicity occurred by the addition of MBCA in the drilling fluid showing that shale stability would be increased [64]. In summary, MBCA proved to be a better inhibitor for sodium bentonite and montmorillonite.

5.2. Low molecular weight amine inhibitors Over the past few years, various amine inhibitors including alkyl primary amines, alkyl secondary amines, alkyl tertiary amines, polyamine acid, quaternary alkyl ammonium salts, ammonium cations, lipophilic polymeric amines, dendritic amines, poly-hydroxylated alkyl ammonium salt, hexamethylendiamine, and polyethoxylated diamines have been introduced as shale inhibitors [161–163]. Various aminebased shale inhibitors are mentioned in Table 2. The shale inhibition efficiency of amines is evaluated by determining the interlayer spacing of clay particles after the adsorption of amines. The inhibitors containing amine groups get protonated in the aqueous solution and turned into a cationic group. The cationic groups of inhibitors attach with the negatively charged surfaces of clay minerals through the electrostatic force of attractions and hydrogen bonding. The electrostatic attraction and hydrogen bonding result in the decrease in zeta potential of clay suspensions which also reduce the

5.2.1. Synergistic effect of organic and inorganic inhibitors The synergistic effect of inorganic and organic inhibitors can also improve inhibition properties. The synergistic effect of various organic and inorganic shale inhibitors has been reported in the literature. The schematic representation of clay swelling inhibition is shown in Fig. 24. A study was conducted using organic cationic salts (quaternary ammonium chloride salt, quaternary polyamine chloride, and cationic polyacrylamide chloride) and inorganic salts (KCl and NaCl) using a capillary suction time test. Longer suction times for specific clays means that a small amount of free water is available in the interlayers of clay and a high amount of water resides in the clay interlayers, indicating a large degree of clay swelling. The distilled water showed a maximum 204

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Table 2 Amine-based shale inhibitors. Amines

Structures

Refs.

Ammonium chloride

[170]

Tetramethyl ammonium chloride

[171]

Hexamethylene diamine

[72]

Polyethoxylated diamine

[172,173]

Polyhydroxylated alkyl ammonium salt

[174]

Polyether diamine

[175]

Poly oxyethylene

[71]

Poly oxyethylene and poly oxypropylene

Poly(oxypropylene)-amidoamine (POAA)

[73]

(continued on next page)

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Table 2 (continued) Amines

Structures

Refs.

Poly oxypropylene

[71]

Poly oxypropylene branched

Amine tartaric salt

[176]

polyethyleneimine

[156]

1,5-pentanediamine

[143]

3-(2-aminoethyl) pentane-1,5-diamine

3,3-Bis(2-aminoethyl)-1,5-pentanediamine

Neutral quaternary ammonium salt

[177]

4,4′-methylenebis-cyclohexanamine

[64]

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Fig. 24. Schematic representation of clay the swelling inhibition mechanism. (a) Without cationic inhibitors (b) with cationic inhibitors [78]. ©Elsevier. Reproduced by permission of Elsevier.

amount of clay swelling because it has maximum suction time. The addition of inorganic salts such as NaCl and KCl sufficiently reduced the suction time and clay swelling. The combination of KCl and cationic polyacrylamide chloride showed the minimum suction time due to the presence of a quaternary ammonium group and high charge density which helps in exchanging a substantial number of exchangeable cations. The overall results indicate that the mixture of inorganic and organic inhibitors presents better swell inhibition compared to the inorganic inhibitor alone [78]. In another study, the synergetic effect of diamino butane and diamino hexane with various hydroxides and chlorides of alkali metals, alkaline earth metals, and transition metal was investigated. The shale inhibition characteristics of these base fluids containing water, aquagel and inorganic compounds were measured using the linear swelling test. The clay minerals containing smectite group mainly showed swelling of clay upon interacting with water compared to the other group of clay minerals such as chlorite, and illite, etc. Of these fluids, only KCl and CaCl2 showed a minimal percentage of linear swelling of clays which indicates their better inhibition properties. When 1% diamino butane and 1% diamino hexane was introduced with KCl and CaCl2, the resulting combination showed less clay swelling depicting the better performance of diamino alkanes. Diamino hexane showed superior performance of shale inhibition in both solutions of KCl and CaCl2 compared to diamino butane. The presence of amino groups at the end of an alkyl group becomes protonated and attached with the adjacent negatively charged layers of clay minerals and reduces the interlayer spacing with less shale swelling. Based on smectite inhibition experiments with superior properties, five different systems of drilling fluids were tested for Marcellus shale inhibition. Constant concentrations of 1% each of salt: LiCl, KCl, NaCl, Ca(OH)2 and Mg(OH)2 were used along with a 0.5% of diamino hexane and 5% aquagel. From all these formulations, the KCl formulation was selected as the best for overall excellent performance in Marcellus shale inhibition, filtration and rheological properties [178,179]. Chitosan quaternary ammonium salt, a biodegradable and environmentally friendly shale inhibitor was chosen to study the shale inhibition properties compared with the conventional polyether amine in oil and gas drilling operations. Chitosan is a naturally occurring polysaccharide having substantial numbers of oxygen, hydrogen and nitrogen atoms. At normal conditions, it is insoluble in water but after

modifying the surface of chitosan by an esterification reaction between quaternary ammonium salt and surface hydroxyl groups of chitosan it becomes water soluble. The zeta potential measurements show the stability of a suspension in water. The pure montmorillonite had a −14.3-mV zeta potential but the addition of a small percentage of chitosan quaternary ammonium salt resulted in the increase of the zeta potential, but further increases in the concentration of ammonium salt up to 2% did not increase the zeta potential. The gel strength measurements also revealed that up to 1% of the gel strengths of four different concentration of montmorillonite samples increased but the further addition of chitosan quaternary ammonium salt did not affect the gel strength values. The shale recovery test showed that chitosan quaternary ammonium salt has a high shale recovery of 95% at 150 °C compared to the polyether amines which has only a 63% shale recovery. The inhibition mechanism of shale could be explained by the adsorption of chitosan quaternary ammonium salt on the negatively charged layers of clay through hydrogen bonding and electrostatic forces and prevent the interactions of water with clay [69]. Chen et al have studied the effect of amine tartaric salt as shale inhibitors for montmorillonite clay. The XRD results showed that interlayer spacing of montmorillonite immersed into water was 1.949 nm whereas the interlayer spacing of montmorillonite dispersion mixed with 0.5% amine tartaric salt decreased to 1.446 nm. This shows that the presence of an inhibiting agent in drilling fluid has a great significance on the inhibition of shale samples [176]. Xie et al. studied the effect of branched polyethyleneimine and 1,6hexamethylenediamine (HMDA) on intercalation behavior of sodium bentonite in an aqueous solution [72]. The adsorption behavior of polyethyleneimine and 1,6-hexamethylenediamine was determined by the Langmuir isotherm and modified Langmuir isotherms. When the concentration of HMDA is < 1.3 CEC, the adsorption capacity of the inhibitor on sodium bentonite increases with the increase in HMDA concentration. When the concentration of HMDA is > 1.5 CEC, then the HMDA inhibitor adsorption capacity increases slowly and approaches the saturation point where no further adsorption takes place. The increase in temperature showing the decrease in adsorption of HMDA indicates that the inhibitor has two terminal amino groups which are strongly attached with the interlayers of sodium bentonite and offers considerable resistance to temperature. The adsorption behavior of BPEI showed that when the concentration of the inhibitor is 0.7 CEC, 207

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Table 3 Ionic liquids used as shale inhibitors. Ionic liquids

Cations

Anions

1-vinyl-3-ethylimidazolium bromide

Refs. [180]

Homopolymer of 1-vinyl-3-ethylimidazolium bromide

1-Hexyl-3-methylimidazolium chloride

[181]

1-Butyl-3-methulimidazolium octyl sulphate

1-Butyl-3-methulimidazolium bromide

1-octyl-3-methylimidazolium tetrafluoroborate

[183]

1-butyl-3-methylimidazolium tetrafluoroborate

[182]

the adsorption of the inhibitor on sodium bentonite approaches the saturation point. The inhibitor BPEI consists of multiple amine groups which attach with the interlayers of sodium bentonite at multiple positions and the increase in temperature also showed the decreasing trend for adsorption capacity of BPEI which indicates its excellent temperature resistance. The saturated adsorbed quantity of BPEI and HMDA on sodium bentonite is 0.74 mmol/g and 1.67 mmol/g at 30 °C, respectively. The results revealed that the saturated adsorption capacity decreased with the increase in a number of amines in the inhibitor. The XRD analysis showed that interlayer spacing increased with hydrated sodium bentonite from 1.011 nm to 1.905 nm compared to dry sodium bentonite. The increase in interlayer spacing showed that sodium bentonite has the ability to swell upon hydration. The intercalation of sodium bentonite was due to the replacement of water molecules from

interlayers of bentonite and strong adsorption of BPEI on the interlayers of bentonite with reduced basal spacing. Further increases in concentration affect interlayer spacing due to the formation of a monolayer between the interlayers. The adsorption of inhibitors on sodium bentonite interlayers involves electrostatic interaction and hydrogen bonding between amine groups and clay sheets. The larger number of amines present in the inhibitor molecules showed a less saturated amount and a high rate of adsorption of inhibitors on sodium bentonite. In summary, nitrogen-based shale inhibitors are widely used in actual field applications. Amine shale inhibitors which have multiple amine groups perform better in terms of swelling inhibition properties. Amines with multiple quaternary groups in the structure attach with various layers of clay minerals and bind them together which results in less hydration of clay minerals in the shale.

208

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[181]

– 30/45.8 28/42.5 18.4/37.5 – – –

– 13.2609 A 12.9501 A 12.5459 A 13.63 A 13.74 A 13.77 A d > 24.10 A d > 24.10 A 14.80 A

– – – – – 35 27.5 26.5 27.5 –

– – – – 39 42 70 62 56 65

– –7 −22.5 −30.5 −17.2 −8.0 +5.3 +7.1 +7.5 –

Ionic liquids are organic salts with a low melting temperature. Ionic liquids are synthesized with various cations including ammonium, imidazolium, piperidinium, and pyrrolidinium. The anions, such as bromide, chloride, and tetrafluoroborate may also vary. Ionic liquids have many industrial applications due to their peculiar properties such as ionic conductivity, low vapor pressure, and specific solvating capacity. Researchers are trying to replace potassium chloride and dimethyl ammonium chloride with ionic liquids for shale inhibition. The structures and characteristics of different ionic liquids are shown in Tables 3 and 4. A recent study investigated the effects of monomer 1-vinyl-3-ethylimidazolium bromide (VeiBr) and its homopolymer (PV) on shale hydration properties in the presence WBDFs [180]. The homopolymer was synthesized by free a radical polymerization process with various concentrations of monomers. At 2 wt% concentration, VeiBr, and its homopolymer were tested for linear swelling with a sodium bentonite pellet and results were compared with the 2,3- epoxy propyl trimethyl ammonium chloride (EPTAC) and potassium chloride. The sodium bentonite pellet immersed in water showed the most swelling. The swelling of the pellet in the KCl and EPTAC was approximately 77% compared to the swelling of the pellet in the deionized water. The shale inhibitor VeiBr showed less swelling (68.6%) as compared to the EPTAC and potassium chloride. In another study, three different ionic liquids were used to study the inhibition characteristics by measuring the swelling properties, interlayer spacing of bentonite, zeta potential, and particle size distribution in the presence of ionic liquids [181]. These ionic liquids were 1- hexyl3-methylimidazolium chloride (IL-1), 1-butyl-3-methylimidazolium octyl-sulphate (IL-2), and 1-butyl-3-methylimidazolium bromide (IL-3). The effects of these ionic liquids on swelling characteristics were determined by XRD analysis which showed that untreated bentonite had 11.74 Å interlayer spacing; while the addition of three ionic liquids increased the interlayer spacing from11.74 Å to 12.54 Å, 12.95 Å and 13.26 Å for IL-1, IL-2, and IL-3, respectively. These results indicate that the presence of ionic liquids intercalated the bentonite structure which also shows the inhibition capability of ionic liquids. The zeta potential measurements showed that at lower concentrations of ionic liquids the zeta potential decreases suggesting that the intercalation and adsorption of ionic liquids on the bentonite. While at high concentration of ionic liquids, the zeta potential does not change much and reaches the equilibrium point which suggests maximum adsorption of ionic liquids on the interlayers of bentonite. The results from zeta potential and particle size analysis showed that intercalation of bentonite platelets with ionic liquids IL-1 and IL-2 are most effective and resulted in enhanced attractive forces and reduced the repulsive forces among bentonite platelets. The comparison of ionic liquids IL-1 and IL-2 with the swelling of bentonite showed that showed maximum swelling was observed with IL-1 ionic liquids due to its capability of forming weakly associated aggregates with each other. These aggregates are so small and do not settle down in the presence of ionic liquids suggesting stable dispersions. Recently, a high thermally stable ionic liquid was tested for rheological and HTHP filtration properties at a temperature of 240 °C with a very low concentration of 0.05 mass% [182]. Various experimental studies such as intercalation behavior, wettability, rheology, capillary suction time, and filtration were carried out. The XRD results of sodium montmorillonite dispersion showed the interlayer spacing around 12.4 Å while with the addition of 0.02% ionic liquid in the dispersion, the interlayer spacing increased from 12.4 to 13.38 indicating the exchange of interlayer cations with the molecules of ionic liquid which increased the distance of interlayers. The hydrophilic part of ionic liquid molecules attached with the negatively charged layer and hydrophilic tail of the ionic liquid acts as a barrier which prevents the interaction of water with clay and hydration of clays are minimized.

81.5 – – – – – – – – 72.8

50.3

–

–

–

–

–

[182]

[185] – – – – – 25.5

5.3. Ionic liquids

200 °C – – – 300 °C 300 °C 300 °C 300 °C 300 °C 300 °C EPTAC stands for 2,3-epoxypropyl trimethylammonium chloride, VeiBr stands for 1-vinyl-3-ethyl imidazolium bromide and PV stands for the homopolymers of for 1vinyl-3-ethyl imidazolium bromide having different molecular weights and high thermal stability. octyl-3-methyl imidazolium tetrafluoroborate and 98% pure

The capability of interlayer spacing, and particle size distribution depends on the size and type of cation.

2 ppm 10 mmol/l 10 mmol/l 10 mmol/l 2 wt% 2 wt% 2 wt% 2 wt% 2 wt% 0.05 wt% (4)

(3)

IL # 2

IL # 3 IL–1 IL-2 IL-3 EPTAC VeiBr PV-1 PV-2 PV-3 ILB (2)

2 ppm

200 °C

Regain permeability with oil is 98.6% and with gas is 119%. Regain permeability with oil is 127% and with gas is 129%. – – – – – – – 200 °C 2 ppm (1)

IL # 1

Used for clay stabilizers and shale inhibitors. IL#1 is the derivative of cyclic quaternary amine. While IL#2 and IL#3 are quaternary ammonium sulfonate compounds. Non-flammable, non-volatile, and are thermally stable.

Thermal stability Concentration Characterizations Materials

Table 4 Characteristics of ionic liquids used for shale inhibition.

Core flow experiment (retained permeability with sandstone core

Capillary suction time test (sec)

Particle size distribution (Dn/ Dw)

Interlayer spacing

Linear swelling (cm)

Shale recovery (%)

Zeta potential

Refs.

H.M. Ahmed, et al.

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Luo et al. have studied the effect of 1-octyl-3-methylimidazolium tetrafluoroborate on hydration and swelling characteristics of sodium montmorillonite clay and the results were compared with the conventionally used shale inhibitors such as potassium chloride and polyether diamine [183]. The capillary suction time test is one of the indicators of shale inhibitor capability. A good quality shale inhibitor is considered one which protects the clay from swelling and dispersion and contains a large amount of free water with flocculated clay particles. On the other hand, a poor-quality shale inhibitor is considered one in which clay swells and there is less free water available in the dispersed system along with no flocculation of clay minerals. The capillary suction time of shale particles in the presence of water was 215 s which indicates the shale was highly dispersed and prone to swell upon interacting with water. The capillary suction time of 5% potassium chloride was 132 s which was less than that of the water system indicating a good inhibition capacity of potassium chloride. The capillary suction time of 0.05% of ionic liquid was only 72.8 s which was higher than 2 wt% polyether amine system and lower than the potassium chloride system. The lower capillary suction time with ionic liquid compared to the potassium chloride makes it a suitable candidate as a shale inhibitor. In summary, ionic liquids are a new class of shale inhibitors recently employed for shale reservoirs to prevent the hydration and swelling of shale formations. Compared to the conventional shale inhibitors, ionic liquids are more efficient and thermally stable for high-temperature applications of the drilling process. The diverse nature of ionic liquids makes them a superior shale inhibitor due to the distinctive hydrophobic alkyl chains which act as insulators for water in drilling applications. The presence of ionic liquids in water-based drilling fluid formulations could be used for better wellbore stability and to preserve formation integrity.

water) and a hydrophobic tail (repelling water molecules). Surfactants are categorized into three different classes: non-ionic, cationic and anionic, based on their active head groups. There are many industrial applications of surfactants but in the petroleum industry, surfactants are employed in the formulation of drilling fluids and enhanced oil recovery techniques. In the applications of enhanced oil recovery, surfactants are utilized to decrease the interfacial tension of water and oil. However, surfactants have many additional applications in drilling fluids such as to: minimize differential pipe sticking, prevent drilled cuttings from sticking with the drilling bit, emulsify the oil and water systems, and the most importantly, shale stability. Among the three categories of surfactants, non-ionic and cationic surfactants are employed for inhibiting shale swelling and hydration. These cationic and non-ionic surfactants adsorb on the surface of swelling clays due to the presence of negative charges and silanol groups on the clay surfaces while their long hydrophobic tails act as a water repellent and prevent the clay minerals from swelling. A schematic diagram which shows the adsorption of surfactant molecule on clay surfaces is shown in Fig. 25. In the following section, the adsorption chemistry of different surfactants on the surface of clay minerals will be discussed. The effect of various surfactant concentrations on the inhibition properties of shales using different experimental techniques such as the hot rolling dispersion test, linear swelling, effect of temperature, zeta potential and X-ray analysis will be discussed. Inhibition performance of tallow amine ethoxylate (surfactant) was investigated by water-based drilling fluids [186]. Untreated bentonite has a strong affinity with water molecules and adsorption of water was determined after 11 days resulting in a 45.23% increase in the weight of bentonite. Whereas, bentonite treated with 2 wt% tallow amine ethoxylate showed water adsorption of only 31.5% compared to the untreated bentonite. This indicates that the lower water adsorption capacity of clay in the presence of surfactants leads to wellbore stability. The wettability alteration test showed that the contact angle of bentonite film on smeary glass was zero whereas the incorporation of tallow amine ethoxylate increased the contact angle from zero to 22.54° which represents enhanced hydrophobicity of bentonite droplet towards the water. Shale recovery experiments were carried out using surfactants and potassium chloride and showed that by the addition of 2 wt% of a surfactant, shale recovery was increased up to 79% compared to the base fluid recovery of only 43% of the shale sample. The overall, experimental results show that the tallow amine ethoxylate surfactant had a better shale inhibition performance. The surfactant has many amine groups in the structure which attach with the oxygen atoms of silicate groups through hydrogen bonding and compete with the water molecules to adsorb on the surface of clay minerals. The superior inhibition performance also showed its compatibility with other drilling fluid components for high-temperature applications [187]. A novel approach was adopted to study the wettability of shale powder by contact angle measurement and other experimental techniques by using the two different surfactant compounds of Twelve alkyl two hydroxyethyl amine oxide (THAO) and polyamine (PA). Contact angle measurements of untreated shale sample and salt-treated shale sample showed zero contact angle while shale samples treated with 1 wt% surfactant compounds showed an increase in contact angle from zero to 48.64 for PA and from zero to 31.5 for THAO. These results indicate that treating the shale with surfactant compounds changes the wettability of the shale surface. The zeta potential measurements showed that incorporation of these surfactant compounds decreased the zeta potential and reduced the hydration of the shale sample by electrostatic repulsion of particles. The surfactant concentration higher than 0.1 wt% has little effect on zeta potential and zeta potential remains unchanged with higher surfactant concentration. The surface hydration of shale powder with water showed 32.7 mg/ g indicating easy hydration of the shale sample. While in the presence of 0.2% of PA and 0.1% THAO, the surface hydration water of the shale

5.4. Surfactants Surfactants (also known as wetting agents) are molecules which are used for lowering the surface tension of water to help in wetting surfaces. Surfactants are composed of a hydrophilic head (affinity for

Fig. 25. Adsorption of surfactant molecules on the surface of clay [185]. ©Elsevier. Reproduced by permission of Elsevier. 210

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Fig. 26. Schematic diagram of PA and THAO adsorption on clay surfaces [188]. ©Elsevier. Reproduced by permission of Elsevier.

structures and are connected to each other through glycoside bonds [190–192]. The hydrophilic side of the molecules consists of saccharide residues while the hydrophobic side consists of triterpenoid and steroid or steroid-alkaloid [193,194]. Increasing the concentration of ZSCE increases the inhibition capacity of the surfactant but the concentration above the critical micelle concentration (CMC) has little effect on the inhibition performance of a surfactant. Below the CMC concentration, free surfactant molecules are available for the inhibition of clay but the concentration above CMC results in the interaction of molecules and formation of micelles with no major change in the free surfactant molecule concentration. The inhibition properties of ZSCE was determined by performing cutting dispersion experiments on highly reactive shale. The percentage of recovery was only 18.25% in the presence of deionized water and the recovery percentage increases with the increase in the concentration of ZSCE. The superior inhibition performance of ZSCE is greater than the two commonly used shale inhibitors of potassium chloride and polyamine. The ZSCE has better hydration inhibition capacity and potential to prevent a shale cutting from the dispersion. The mechanism of the inhibition of ZSCE is explained by the interactions of surfactant molecules with the clay surfaces. ZSCE contains saponins with hydrophobic and hydrophilic moieties. The hydrophilic part of ZCSE attaches with the negatively charged surfaces while hydrophobic part of ZSCE is oriented towards the aqueous phase as shown in Fig. 28. The ZCSE molecules attach with the clay surface through hydrogen bonding between hydroxyl groups of ZSCE and oxygen atoms of the clay surface. The ZSCE molecules compete with the water molecules and increasing concentrations of ZCSE enhance the hydrophobicity of the shale surface which prevents the hydration and swelling of shale formations. A combination of cationic and anionic surfactants can reduce the surface tension and enhance the contact angle with the shale surface. Various experimental techniques were used to study the inhibition mechanism with 0.1 wt% sodium dodecyl benzene sulfonate (SDBS) and 0.2 wt% cetyltrimethylammonium bromide (CTAB). The results show that at higher temperature and salinity conditions, the performance of the surfactant decreases. The swelling rate of shale was slightly greater than 7% in the presence of fresh water. While the swelling rate of shale was greatly reduced in the presence of CTAB and SDBS surfactants to approximately 4%. The results show that higher temperature has less effect on the swelling rate of shale and surfactant solution has a superior temperature tolerance. The surfactant molecules of CTAB and SDBS were used in combination to improve the inhibition performance. The anionic surfactant was used to reduce the surface tension and to block the pores at the shale surface [195]. The CTAB surfactant adsorbs on the surface of shale through ionic attractions because CTAB contains positive charge and the shale surface has negative charges and both strongly attract each other. The hydrophilic end of CTAB is oriented toward the solid shale surface while the hydrophobic end of the surfactant is oriented away from the shale surface

Fig. 27. Chemical structure of Saponins [194]. ©ACS Publications. Reproduced by permission of ACS Publications.

sample declined to 18.31 mg/g. The surface hydration reduction was due to the adsorption of surfactant compounds on the surface and reduced the interaction of water with shale. The interlayer spacing of untreated shale power was 1.033 nm in the dry form while the treated shale sample with 0.3% of PA and THAO, the interlayer spacing was further reduced to 1.006 nm and 1.015 nm, respectively. The reduction in the interlayer spacing was due to the intercalation of shale powder with surfactant compounds and it is believed that these surfactants were adsorbed on the clay minerals by hydrogen bonding with a monolayer formation [188]. The schematic diagram in Fig. 26 represents the adsorption of surfactant molecules on negatively charged layers of clay minerals. It is believed that PA molecules contain amine groups which make hydrogen bonding with the silicon-oxygen alkyl groups found on the clay surface through irreversible adsorption [189]. The hydrophobic nature of shale surface was improved with the alkyl groups present in the structure of PA which prevents the interaction of water with shale. The surfactant THAO also showed similar hydrogen bonding interactions with the clay surface. The demand for environmentally friendly and less toxic shale inhibitors is increasing due to the requirements of the drilling industry. A newly developed shale inhibitor Zizyphus spina-christi extract (ZSCE) was used for shale inhibitions and inhibition performance was compared with the conventionally used polyamine and potassium chloride. The non-ionic biosurfactant was extracted from trees extracted by a spray drier method and it is believed that it contains a high concentration of saponins which have complex structures as shown in Fig. 27. The saponin molecules have both hydrophilic and hydrophobic 211

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Fig. 28. Schematic adsorption of ZSCE on the shale surface [199]. ©Elsevier. Reproduced by permission of Elsevier.

which reduces the surface energy of shale and increases the contact angle as shown in Figs. 28 and 29 [196]. In summary, the non-ionic and cationic surfactant molecules are used to enhance the wellbore stability of shale formations by altering the surface tension and wettability of shale. Most importantly, some of the surfactants can be used for high temperature applications. Another important benefit of surfactants in water-based drilling fluids is lower toxicity, especially for marine drilling applications.

gas industry has shifted their interest from vertical drilling processes to horizontal or multilateral drilling process to enhance the production of oil and gas. There are many challenges associated with conventionally used shale inhibitors in water-based drilling fluids which include the ammonia-based salts, quaternary alkyl ammonium salts, polyamines, polyhydroxylated alkyl ammonium salt, quaternary amines, polyhydroxy diamines, and primary diamines. Ammonium cations from the salt have a similar radius as potassium cations and penetrate into the interlayers and replace the conventional sodium or calcium cation from clay and act as shale inhibitor. The main advantages of ammonia-based salts are that they are cheap and can be employed with acidic and basic environments and applied in chloride free environments. The main challenge associated with ammonia-based salts is their thermal stability. Ammonia salts are pH sensitive and temperature sensitive. They cannot be used at high temperatures (150°F) and high pH conditions. However, most of the drilling operations are conducted at high temperature using high pH fluids. At these conditions, odorous ammonia is produced because of the reaction of ammonia-based salts. Quaternary alkyl ammonium salts are the derivatives of ammonia and are made by replacing the hydrogen of ammonia with an alkyl group. This class shows better inhibition properties compared to the ammonia salt inhibitors because these inhibitors have less odor and are more effective at low concentrations. The simplest example of this class of inhibitors is tetramethyl ammonium chloride. Quaternary ammonium alkyl salt is extremely pH dependent and it shows good properties at low pH levels. High molecular weight salts are not compatible with anionic drilling fluids and affect the marine environment when used in

6. Challenges and future prospects Shale inhibitors are extremely important to protect the wellbore integrity during the drilling process of shale reservoirs. Previously, oilbased drilling fluids were frequently employed for the drilling of shale reservoirs and to minimize the invasion of drilling fluid into the formations. Oil-based drilling fluids have superior shale inhibition capacity compared to the water-based drilling fluids and oil molecules of the oil-based drilling fluid cannot penetrate into the tiny non-organic and organic pores of shale formations during the drilling process. Further, oil-based drilling fluids have better ability to protect the shale formations with minimum efforts in the drilling process. But, due to the strict environmental regulations and the waste disposal issues of the extremely toxic oil-based drilling fluids, they cannot be directly disposed in the land or in the oceans, which irrespective of legal implications could affect the environment and marine life for years to come. In comparison to oil-based drilling fluids, water-based drilling fluids are considered environmentally friendly, low cost and, with shale inhibitors, they also have good inhibition properties. Recently, the oil and

Fig. 29. Mechanism of CTAB adsorption on the surface of shale [196]. ©Elsevier. Reproduced by permission of Elsevier.

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the offshore drilling operations. Among all the amine-based shale inhibitors, polyether amines are considered as excellent shale inhibitors due to lower marine toxicity, compatibility with most of the waterbased drilling fluids, less ammonia odor, and high temperature stability. Furthermore, the unique structure of polyether diamine is suitable for the best inhibition properties of shale because PEA molecules easily migrate between the interlayer spaces and replace the interlayer cations. To get the optimum performance with PEA, a less saline environment and absence of potassium chloride effectively enhance the shale inhibition properties. The drilling industry has shifted their interest towards the new materials such as polymers and polymer nanocomposites as drilling fluid additives due to the excellent inhibition properties and fewer environmental impacts. Polymers and polymer nanocomposites are widely employed as drilling fluid additives and are also used as shale inhibitors. The selection of polymer additives as shale inhibitors in the water-based drilling fluid depends on ionic charge density of polymer chains. Polymers containing a positive charge are preferred for shale inhibition applications rather than using a polymer having no charge or a negative charge on polymer chains. The copolymer has recently been used as a multipurpose additive in the water-based drilling fluid in order to modify the rheological properties, enhance the high temperature and high pressure applications of drilling fluids as well as to modify the inhibition properties of drilling fluids [108–110,197]. Several polymers have been utilized in drilling fluids as additives for shale inhibition applications such as poly glycols, zwitterionic polymers, and a cationic polymer. Poly glycols, zwitterionic polymers, and cationic polymers have limited applications in shale inhibition because these polymers are severely affected by high salinity and high-temperature conditions. Whereas in the absence of high temperature and high salinity, cationic polymer shows enhanced shale inhibition. The cationic part of polymer attached with the negatively charged surface and produce large size agglomerates which suggest superior inhibition properties. Similarly, polymer nanocomposites are also utilized in shale inhibition applications because of the presence of nanoparticles which have good thermal stability and plug the pores of shale. Development of polymeric inhibitors that are stable under high salinity and high temperature environments will resolve several issues related to different types of inhibitors. Recently, a new class of shale inhibitors “ionic liquids,” has been suggested for shale inhibition applications in water-based drilling fluids. Ionic liquids have excellent thermal stability for high-temperature reservoir applications. Furthermore, ionic liquids show superior shale inhibition properties compared to the polymer-based and aminebased shale inhibitors. In summary, the polymers, polymer nanocomposites, and ionic liquids with high thermal stability are considered as promising shale inhibitors for future applications in the drilling of oil and gas reservoirs. However, the practical implementations of ionic liquids, copolymers, and nanocomposites as shale inhibitors in drilling fluid additives need to be considered. The synthesis cost of copolymers and polymer nanocomposites, their toxicity, and hazard analysis for real field applications should be considered. Although there is limited literature available on copolymers, polymer nanocomposites, and ionic liquids as shale inhibitors, the lab scale analysis of shale inhibition has proven them to a strong candidate for shale inhibition applications in water-based drilling fluids.

and crystalline swelling have been discussed in detail. Several techniques were discussed in detail for characterizing shales and the performance of shale inhibitors. The main literature discussed the aminebased inhibitors, polymer-based inhibitors, and ionic liquid-based shale inhibitors.

• The • • • • • • • • •

amine-based inhibitors are good compared to potassium chloride which has been conventionally used for shale inhibition applications. Ammonium compounds replace the interlayer cation and adsorb on the negatively charged layers of shale. These amine-based inhibitors were also useful for enhanced shale inhibition properties because amine compounds compete with the water molecules in the shale and prevent the shale from hydration and swelling. Amine inhibitors have several limitations including thermal stability, pH sensitivity and cannot be used for marine environment applications of the drilling process. The polymer-based shale inhibitors are cheap, environmentally friendly, less pH sensitive compared to the amine-based inhibitors and have superior shale inhibition properties. Especially, cationic polymers attach to the negatively charged layers of clay minerals in the shale and protect them from hydration and swelling. The polymer also adsorbs on the shale formations in the wellbore and makes a thin layer which prevents the invasion of drilling fluid in shale formations. There are some limitations of using polymers in water-based drilling fluids as shale inhibitors. The polymer can degrade at high-temperature applications, especially cationic polymers result in the flocculation of bentonite clay in the water-based drilling fluids which causes the segregation of drilling fluid components. To avoid these limitations, high molecular weight copolymer has recently been recommended. Ionic liquids have evolved as a novel class of shale inhibitors and their superior shale inhibition properties are comparable to the amine inhibitors and polymeric shale inhibitors. Ionic liquids have high thermal stability up to 300 °C and have high salt resistance in shale inhibition applications. Although there is limited literature on ionic liquids and surfactant as shale inhibitors, their remarkable shale inhibition properties make them a superior class for shale inhibition applications. There are multiple applications of polymeric and low molecular weight shale inhibitors. The specific application of a shale inhibitor depends on the ionicity, molecular weight, interaction with the shale surface and stability in the water-based drilling fluid. The selection of a shale inhibitor is done based on its solubility in the drilling formulations, toxicity, and stability under high temperature and pressure conditions.

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