Application of Ionic Liquid and Polymeric Ionic Liquid as Shale

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Application of ionic liquid and polymeric ionic liquid as shale hydration inhibitors Lili Yang, Guancheng Jiang, Yawei Shi, and Xiao Yang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00272 • Publication Date (Web): 16 Mar 2017 Downloaded from http://pubs.acs.org on March 23, 2017

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Energy & Fuels

Application of ionic liquid and polymeric ionic liquid as shale hydration inhibitors Lili Yangab, *, Guancheng Jiangab,*,Yawei Shiab, Xiao Yangab a

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing), Beijing 102249, China b

MOE Key Laboratory of Petroleum Engineering, China University of Petroleum, (Beijing), Changping District, Beijing 102249, China

* Corresponding

author. Tel.: +86 10 89732239; fax: +86 10 8973 2196 E-mail address: [email protected] ( L. Yang)

ACS Paragon Plus Environment

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ABSTRACT

2

Shale hydration and swelling are disadvantageous for well drilling, especially when

3

using

4

1-vinyl-3-ethylimidazolium bromide (VeiBr) monomer and its corresponding

5

homopolymers (PV) were innovatively utilized as shale hydration inhibitors. Both

6

composites of Na-bentonite (Na-BT) with VeiBr and PV (hereafter denoted as

7

Na-BT/VeiBr and Na-BT/PV composites) exhibited excellent temperature stability up

8

to 300 °C, showing potential application in high-temperature well drilling. The

9

inhibiting performance was evaluated by measuring the linear swelling height,

10

rheological property of Na-BT aqueous solutions, and recovery percentage of shale

11

cuttings after hot rolling. Results indicated that VeiBr monomer and PV polymer

12

displayed better inhibition performance than inorganic KCl and organic quaternary

13

amine 2,3-epoxypropyltrimethylammonium chloride in all tests. In addition, PV was

14

even better than VeiBr. The underlying mechanism was analyzed by measuring the

15

interlayer distance through X-ray diffraction, observing the aggregation through

16

scanning electron microscopy, and determining the zeta potential and particle-size

17

distribution. The monomer exerted its effect mainly by decreasing the interlayer

18

spacing, whereas the polymer increased the viscosity, encapsulated Na-BT particles,

19

prevented the exfoliation of Na-BT, and decreased the interlayer spacing depending

20

on the molecular weight. This study can serve as a basis for using ionic liquids in the

21

design of permanent shale inhibitors for drilling fluids.

water-based

drilling

fluids.

In

this

work,


the

ionic

liquid

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Key Words: Ionic liquid, Polymeric ionic liquid, Shale hydration inhibitor,

23

Bentonite

24

1. INTRODUCTION

25

Shale hydration is an unavoidable problem when drilling unconventional shale gas

26

and oil using water-based drilling fluids (WBDFs). The severe hydration and swelling

27

of shale can narrow the bore diameter, alter the stress distribution around the borehole,

28

reduce the mechanical intensity of shale, cause the instability of the borehole, and

29

eventually lead to a delay in drilling and an increase in oil-well construction costs.1-3

30

Therefore, mitigating the shale hydration during drilling is important. In some

31

extremely easy-hydrated areas, oil-based drilling fluids (OBDFs) were often applied

32

in case of serious shale hydration and swelling. However, OBDFs are expensive,

33

disadvantageous to well logging, and polluting the environment, especially when used

34

in off-shore drilling. WBDFs are cheap, have no influence on well logging, and are

35

environmentally friendly. Therefore, OBDFs must be eliminated and replaced by

36

WBDFs, containing effective inhibiting additives.

37

To develop effective shale inhibitors, obtaining insights into the mechanism of shale

38

swelling is important; this has been considered in detail by various authors.4-6 Water

39

in drilling fluids, completion fluids, and fracturing fluids enter the shale formations

40

inevitably; though many additives are used to control the invasion of fluids in the

41

natural or induced fractures, natural flow channels, or pores by a physical plug. Shale

42

formations contain a high fraction of montmorillonite (MMT). Isomorphic

43

substitution of metal atoms in the clay lattice leads to an overall negative charge on


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individual layers, which tend to be compensated by cations existing in the interlayer

45

region. The usual inorganic cations, such as Na+ and Ca2+, in naturally occurring clays

46

easily adsorb water by crystalline hydration and osmosis hydration, which would

47

increase the interlayer space and interparticle void, respectively. The thorough

48

crystalline swelling can increase the interlayer space from 10 Å to 20 Å. Osmosis

49

steeply increases the space to 35–40 Å by the formation of repulsive diffused double

50

layers continuously increase to several hundred angstroms with water content.7 The

51

magnitude of swelling is controlled by the water content, accessible counter-ions, and

52

ionic strength. A variety of experimentation and theoretical research were conducted

53

on percentage of interlayer space and interparticle void.8-10 Salles found that in the

54

free swelling of Na-MMT, the interlayer cations strongly influenced the size and the

55

behavior of the swelling of mesopores, which occurred before the complete filling of

56

the interlayer space. However, the interlayer is the predominant space where the water

57

is adsorbed compared to mesopores.11

58

Different chemicals have been added to the drilling fluid to control the swelling of

59

Na-bentonite (BT). Potassium salts can suppress the swelling of the clay minerals via

60

ion exchange with sodium, and have been mostly utilized in practice in combination

61

with a variety of polymers.12, 13 Unfortunately, the required high concentrations of

62

KCl can affect the ecosystem, and the direct disposal of which has been prohibited. To

63

avoid the adverse effect on the environment, alternative organic cationic ions

64

behaving like potassium ions, including amine and the derivatives, were developed,


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polyamine

acid14,

65

namely,

hexamethylendiamine,

polyethoxylated

66

lipophilic polymeric amines, and dendritic amines.15, 16 The oligomeric and polymeric

67

amine can prevent water from entering shale, and those that entered the clay sheets

68

can replace hydrated cations. Suter et al. also proposed the rule in designing

69

clay-swelling inhibitors through molecular simulation.17 However, all these amines

70

displayed pH-dependent inhibition performance for amine deprotonation as pH

71

increases, which is not suitable for rough practical conditions. Quaternary ammonium

72

salts can avoid the influence of pH, increase hydrophobicity, and enhance

73

shale-swelling inhibition performance.18 However, tertiary amine was neglected,

74

though it might display comparable shale inhibition property, because it is less

75

influenced by pH compared with primary amine, and its size is smaller than

76

quaternary amine.

77

Ionic liquid is organic salt with low melting temperature. Ionic liquids can be

78

produced with a variety of cations and anions that imidazolium-, pyrrolidinium-,

79

ammonium-, and piperidinium-based ionic liquids were classified based on the

80

consistent cation. Ionic liquids have been successfully applied in many industrial

81

fields due to their unique properties such as low vapor pressure, ionic conductivity,

82

and specific solvating ability.19 Attempts to apply ionic liquid as permanent

83

shale-swelling inhibitor to replace KCl, and KCl to substitute trimethylammonium

84

chloride were performed.20 In the present study, we set the imidazolium-based ionic

85

liquid, that is, 1-vinyl-3-ethylimidazolium bromide (VeiBr) as an example of tertiary


diamines,

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amines, and investigate its inhibition performance on Na-BT hydration, swelling, and

87

dispersion. Poly(ionic liquid) is a high-molecular-mass compound containing ionic

88

liquid monomer unites. Polymeric inhibitor can be adsorbed by clay via multipoint

89

adsorption, can prevent drilling fluids penetrating into shale and intensify the shale.18

90

Therefore, polymeric VeiBr (PV) was also synthesized to evaluate systematically the

91

inhibition performance of monomers and polymers with the same composition. In

92

addition, imidazoline is widely used in formulating the corrosion products for

93

application in oil and gas industries,21 beneficial in preparing additives possessing

94

multiple functions.

95

Layered clay minerals are aligned parallel to the bedding plane, resulting in a

96

laminated–textured shale along the bedding direction macroscopically. Therefore, the

97

shale has anisotropic mechanical and swelling properties. A number of investigations

98

by experiments addressed the nature of swelling arising from Na-BT particles and

99

membranes that expanded freely in static aqueous and electrolyte solutions11, 22 or

100

water infiltrated into pressed Na-BT powders within a confined reaction volume.23 In

101

this study, we mainly observed the free swelling behavior of Na-BT pellets and

102

powders in aqueous solutions with VeiBr and PV, and analyzed the underlying

103

mechanism. This study is also beneficial to the preparation of polymer-clay

104

nanocomposite materials.24, 25

105

2. EXPERIMENTAL

106

2.1. Materials.


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1-vinyl-3-ethylimidazolium bromide (VeiBr) was supplied by Lanzhou Institute of

108

Chemical

109

2,2′-azobis(2-methylpropionamidine)

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2,3-epoxypropyltrimethylammonium chloride (EPTAC) were obtained from Energy

111

Chemical (China). The Na-BT used in linear swelling height and rheological

112

measurement was a commercial product purchased from Weifang Huawei New

113

Materials Technology Co., Ltd. (China). It consisted of mainly clay (59.8 %) and

114

other non-clay content (40.2 %). The shale used for hot rolling recovery was obtained

115

from CNPC Chuanqing Drilling Engineering Co. Ltd (China). All other chemicals

116

used were of analytical grade and without further purification (Beijing Chemical

117

Reagent Factory, China).

118

2.2. Synthesis of polymeric VeiBr (PV).

119

PV was synthesized through a typical free radical polymerization procedure. A certain

120

amount of VeiBr (1.5 g, 3.0 g and 6.0 g), initiator V-50 (50 mg), and deionized water,

121

i.e. DI water (120 mL) were added into a 250 mL three-necked round-bottom flask,

122

then the mixture was stirred with a mechanical agitation until complete dissolution.

123

The polymerization could proceed at 60 °C for 4 h under nitrogen atmosphere. The

124

resultant mixture was dialyzed against distilled water for 4 days and lyophilized until

125

constant weight. The as-prepared homopolymers were labeled as PV-1, PV-2, and

126

PV-3. The molecular weight of polymers PV-1, PV-2, and PV-3 was in the range of

127

500–1000, 1000–3500, and >3500, respectively, according to the molecular weight

Physics,

Chinese

Academy

of

dihydrochloride


Sciences (V-50)

(China). and

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cut-off of the dialysis bag used in the purification process.

129

2.3. Characterization of PV.

130

The 1H nuclear magnetic resonance (NMR) spectrum of PV was recorded with a

131

Bruker AV 400 NMR apparatus. Deuterium oxide (D2O) was used as solvent, and the

132

signals were referenced to those of the residual protonated solvent at δ=4.79 ppm.

133

TGA curves were constructed using PE Pyris 1 in the temperature range of 30 °C to

134

700 °C, at a heating rate of 10 °C/min, and under a constant 20 mL min-1 N2 gas flow.

135

In this technique, the mass of the substance was determined as a function of

136

temperature.

137

2.4. Inhibition performance of PV.

138

The inhibition effect of VeiBr and PV on the hydrated dispersion of Na-BT was

139

evaluated using ZNN-D6L rotational viscometer (Qingdao, China) in comparison

140

with KCl and EPTAC. 12 g Na-BT was suspended into 300 g DI water or inhibitor

141

solution. After high-speed stirring at room temperature for 30 min, the apparent

142

viscosity (AV), plastic viscosity (PV), and yield point (YP) of the Na-BT /inhibitor

143

suspension was determined. 12 g Na-BT was added again, and stirred for another 30

144

min for the next measurement until the AV was too high to be measured. The effect of

145

Na-BT concentration on rheological property was compared with the inhibition ability

146

of the inhibitor on Na-BT dispersion behavior. The viscosity measurements were

147

conducted at fixed rates of 600, 300, 100, 20, 6, and 3 rpm, respectively. AV, PV, and

148

YP were calculated according to the following equations:

149

AV=θ600/2

(1)

150

PV=θ600 – θ300

(2)

151

YP=0.511(θ300 – PV)

(3)

152

where θ600 and θ300 are the viscosity at 600 and 300 rpm, respectively.

153

The swelling behavior of compacted Na-BT immersed in different inhibitor solutions

154

was determined utilizing a CPZ-2 dual channel linear swell meter. For measurement,

155

Na-BT (5 g) was compressed into a cylindrical device under 10 MPa pressure for 5


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min. Then, 15 mL inhibitor solution was added to immerse the bentonite pellet. The

157

height of the pellet was recorded every 30 s through the transducer for 24 h.

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The inhibition performance of the dispersion of shale cuttings for a period at a high

159

temperature, mimicking the trial, was evaluated by hot rolling tests. 20 g shale

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cuttings with 6–10 mesh size (diameter = 2.0–3.2 mm) were hot rolled in a 300 mL of

161

DI water or inhibitor solution at 120 °C for 16 h. After cooling down, the remaining

162

cuttings were screened using a 40-mesh sieve, and washed with DI water to remove

163

the shale fragments. Then, the cuttings retained on the sieve were dried at 105 °C until

164

constant weight. The recovery percentage was calculated by the following equation.

165

Recovery percentage =

× 100%

(4)

166

where m0 is the mass weight of shale cuttings before hot rolling, and m is the mass

167

weight of shale cuttings after hot rolling.

168

2.5. Microstructural analysis.

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8 g Na-BT was added into 200 mL DI water, and stirred for 12 h before use. 4 mL

170

inhibitor (2.0 wt.%) solution was added into 4 mL supernatant Na-BT solution to

171

compare the influence of different inhibitor on the microstructure.

172

The dispersion was stirred for 24 h and centrifuged for 30 min before the

173

precipitations were collected. One part of the precipitations was directly used for

174

XRD measurements. The other part of the precipitations was dried in vacuum at

175

105 °C overnight and then crushed with a pestle and mortar for measurement. The

176

influence of concentration of VeiBr, ranging from 0 to 2.0 wt.%, on the interlayer

177

spacing was also characterized. XRD analysis was performed by a Rigaku X-ray

178

generator with Cu target (λ=1.5406 Å) at a generator voltage of 40 KV, and current of

179

20 mA. Samples were measured from 2° to 15° at a scanning rate of 0.5 °/min. The

180

basal spacing was analyzed using Bragg’s equation.

181

The exterior morphology of pure Na-BT suspension before and after mixing with

182

different inhibitor solutions was observed by Olympus BX51 polarizing microscopy

183

(POM) with a total magnification of 40. The inner morphology was observed by


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SU8010 scanning electron microscopy (SEM) at an accelerating voltage of 10 KV.

185

The particle-size distribution of PASV/ Na-BT-WDFs was determined using a

186

Malvern Mastersizer 2000 particle size analyzer. The concentration of all samples was

187

approximately 10.0 g·L-1.

188

The zeta potential was measured by Malvern Zetasizer Nano series. The concentration

189

of all samples was approximately 0.1 g·L-1.

190

3. RESULTS AND DISCUSSIONS

191

3.1 Characterization of PVeiBr

192

VeiBr was easily polymerized via a facile free radical polymerization method.26, 27. 1H

193

NMR spectroscopy was employed to characterize the structure of the resultant

194

product. As shown in Figure 1, vinyl protons were present in VeiBr (Figure 1a) at

195

5.3–5.8 ppm, then disappeared in PV. Simultaneously, a new peak between 2.0 ppm

196

and 3.0 ppm appeared and was assigned to newly formed methylene protons band

197

(Figure 1b), indicating the success of polymerization. In addition, the peaks at 7.7–7.0,

198

4.5–3.6, and 1.5–1.2 ppm were attributed to protons of vinylidene between two

199

nitrogen atoms, methine protons, and methyl protons of terminal ethyl on side chain.

200

The characteristic peaks of PV were broader than that of the monomer.

201

Thermal stability is important to additives in drilling fluids. Figure 2a shows that

202

Na-BT/KCl composite has similar thermal decomposition degree with pure Na-BT at

203

less than 10%. Na-BT/organic inhibitor composites would decompose severely over a

204

certain temperature. The initial decomposition temperature of Na-BT/EPTAC is

205

approximately 210 °C, whereas that of Na-BT/VeiBr is 250 °C, displaying a better

206

thermal stability. The thermal decomposition temperature of Na-BT/PV composites


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increased to 300 °C, further improving the thermal stability, and showing possibility

208

to be used as shale inhibitor at high temperature. The quantities of inhibitor in

209

Na-BT/inhibitor were calculated from the difference in the weight loss determined

210

from Na-BT and the Na-BT/inhibitor at 700 °C, neglecting the trace of adsorbed

211

water (Table 1). The curves of all Na-BT/PV composites were similar, inferring the

212

similar adsorption manner and amount of PV in Na-BT. The higher decomposition

213

amount and faster decomposition rate of PV over the onset temperature might be

214

because more PV was adsorbed on the surface of Na-BT. Thus, PV immediately

215

decomposed given the high temperature, whereas a considerable part of VeiBr and

216

EPTAC entered the interlayer space of Na-BT, which impede the thermal

217

decomposition process, as compared in Figure 2b.28

218

Thermal gravity analysis can also reveal the distribution of water in a clay. MMT (K-,

219

Ca-, and Sr- samples) easily adsorbs water, maintaining a homogeneous dehydrated

220

state only when relative humidity (RH) is 0 %.29 Three water states are in Na-BT,

221

including free adsorbed water, loosely coupled water, and close coupled water. The

222

evaporation of these water states corresponds to the three stages during the thermal

223

decomposition of Na-BT/inhibitor composites, i.e., EPTAC > KCl. Their molar concentration at 2.0 wt.% are in an ascending

285

order: VeiBr < EPTAC < KCl. Therefore, the inhibition property of VeiBr is better

286

than KCl and EPMAC under the same mass or molar concentration. After

287

polymerization, PV-1, PV-2, and PV-3 decreased the swelling degrees of Na-BT to

288

51.9 %, 50.5 %, and 51.1 %, respectively. The inhibition effect can be enhanced by

289

the polymerization method. All the linear swelling results accorded with rheological

290

results showing that VeiBr and PV have superior inhibition effects on the hydration


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291

and swelling of Na-BT.

292

The influence of the concentration of VeiBr monomer and PV on linear swelling

293

degree of Na-BT pellet was also considered. Figure 6 shows that the inhibition effect

294

improved by increasing the concentration of both VeiBr monomer and polymers. The

295

inhibition effect of PV was better than VeiBr at each concentration. For example,

296

when the monomer concentration was 0.25 %, 0.5 %, 1.0 %, and 2.0 %, the swelling

297

height of Na-BT pellet in VeiBr aqueous solution was 5.40, 4.64, 4.29, and 3.61 mm

298

(Figure 6a), respectively. In addition, replacing VeiBr with PV-1, the swelling height

299

was reduced to 4.74, 4.15, 3.37, and 2.73 mm (Figure 6b). When the molecular weight

300

increased, the inhibition performance improved, which was much evident at low

301

concentrations of inhibitor (0.25 wt.% and 0.50 wt.%).The primary composition was

302

entirely the same except for the ethylene functionality of the monomer, the main

303

difference between VeiBr and PV was the molecular weight. The difference in the

304

molecular weight directly results in the different viscosity and hydrodynamic volume.

305

A higher viscosity and larger hydrodynamic volume usually mean greater difficulty

306

for water in penetrating into hard Na-BT pellet.

307

Shale recovery test is a common method in oil industry that assesses the inhibitive

308

properties of a drilling fluid in controlling the disintegration of drilled cuttings

309

transported from drill bit to the surface. After hot rolling in a 120 °C atmosphere for

310

16 h, the remaining shale in fresh water accounted for only 25.0%–30.0% depending

311

on the sample source and preparation condition. By adding 1.0 wt.% KCl, similar


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amount of shale cuttings as that in fresh water was obtained, and EPTAC and VeiBr

313

increased the recovery percentage by 7%–12%. This result was due to the weak ionic

314

effects of KCl with shale, whereas a part of EPTAC and VeiBr adsorb on the shale.5, 31

315

PV further increased the recovery percentage to 52%–57%, and recovery percentage

316

increased with molecular weight (Figure 7a). The excellent improvement of inhibition

317

is attributed to strong adsorption of PV on shale cuttings and the bridging action in

318

individual shale. When 2% inhibitor was added, no increase in recovery percentage

319

was observed except PV-1 (Figure 7b) and recovery percentage decreased with

320

molecular weight. Similar with the results in linear swelling and Na-BT dispersion

321

test, disintegration and dispersion of drilled cuttings are much effectively inhibited

322

during their removal from the wellbore by VeiBr and especially the PV compared with

323

KCl and EPTAC.

324

3.3 Microstructural analysis

325

Many driving forces contribute to the transport of water into shale, such as diffusion,

326

capillarity, clay swelling, and osmotic potential. Many natural or induced fractures,

327

natural flow channels, or pores are in interior of shale that drilling fluids and

328

completion fluids easily invade. Most additives can create a physical plug, such as

329

asphaltenes, graphite, calcium carbonate, and other solids. Nanoparticles and

330

copolymers were also developed as sealing products that minimize diffusion amount

331

and capillarity effect. By encapsulation mechanism, the polymeric ionic liquid (PV-1,

332

PV-2, and PV-3) in our study prevented the invasion of water. The small molecules


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can increase the ionic concentration of water phase, and retard osmotic hydration.

334

The invaded water into shale can induce the swelling of clay, which is a multiscale

335

process including the two hydration and expansion processes. The first process

336

involves the increase in distance between the lamellae within each particle. The

337

second process of Na-BT swelling is the increase in the wall-to-wall distance in the

338

mesoscale voids between particles. When water approaches the Na-BT surface, it will

339

be adsorbed into the interlayer region of the clay, initiating crystalline swelling. Water

340

can also penetrate the interlayer space by osmotic swelling ultimately driven by ionic

341

concentration and osmotic pressure. To interpret the role inhibitor played in this

342

process, XRD was used to measure the (001) interlayer spacing (d001) of the silicate

343

layers. Typical interlayer spacing recorded in the crystalline swelling regime lie in the

344

range of 9 Å to 20 Å. Osmotic swelling can result in significant increase in interlayer

345

spacing from > 20 to 130 Å. In our study, the d-spacing of Na-BT in DI water were

346

15.72 Å and 18.38 Å (Figure 8a), indicating that two and three water layers coexisted

347

between the silicate layers. Na+ can form an outer-sphere surface complex with

348

interlayer water molecules strongly bound to the tetrahedral substitution sites of the

349

clay layer. Therefore Na-BT is a strong swelling clay. When KCl, EPTAC, and VeiBr

350

were added, Na+ can be exchanged with weak hydrated K+, EPMTC, and VeiBr. The

351

d-spacing decreased to 14.96 Å, 14.29 Å, and 13.57 Å, showing that water molecules

352

were expelled from the interplanar space, and the water layers decreased. Potassium

353

ion preferentially forms inner-spheres similar to illite possessing smaller interlayer


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354

distance. No water molecule is interposed between the surface functional group and

355

the small cations; thus, inhibiting crystalline swelling. It accorded well with the

356

rheological results mentioned above. For VeiBr, the d-spacing reduced to 13.57 Å

357

when the concentration was 2.0 wt.%, showing excellent inhibition performance on

358

hydration of Na-BT. EPMTAC and VeiBr adopted monolayer adsorption, and

359

decreased the hydrophilicity of Na-BT owing to the existence of alkyl content. The

360

better inhibition effect of VeiBr might be related to stronger hydrophobicity or larger

361

volume because no adsorption amount of VeiBr was observed by TGA curves (Figure

362

2a) and XRD analysis (Figure 8b). However, though PV has a positive influence on

363

inhibiting the swelling and dispersion of Na-BT, no pronounced decreasing trend of

364

d-spacing after adding PV as the inhibitor was presented, as shown in Figure 8,

365

similar to PHPA.33 PV-1 is an oligomeric ionic liquid because only two to four VeiBr

366

monomers are in a PV-1 polymer. Therefore, PV-1 can enter the interlayer space; thus,

367

only one peak approximately 15.27 Å was observed, showing a slight decrease in

368

crystalline swelling. Though no decease in d-spacing was attained by PV-2 and PV-3,

369

the XRD patterns changed, which might imply that for chains of PV-2 and PV-3 is

370

still short enough and slight amount of them entered the interlayer space. For dry

371

samples, d001 of Na-BT was 12.55 Å, whereas the small molecule EPMTC and VeiBr

372

increased d001 to 13.63 Å and 13.74 Å, inferring monolayer arrangement for EPMTC

373

and VeiBr. Adding polymer can increase d001 to above 24.10 Å, suggesting that PV is

374

a multilayer arrangement. The increase in d001 of Na-BT/PV in the dry state compared


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375

with that in the wet state is attributed to the increase in temperature in the process of

376

dryness, which is a condition for intercalation and exfoliation.32

377

The results of Na-BT dispersion inhibition show that in the linear swelling inhibition

378

test and shale recovery test, VeiBr and PV display excellent inhibition performance on

379

hydration, swelling, and dispersion of Na-BT. To explain this phenomenon,

380

electrokinetic potential must be measured. Inhibitors, depending on the structure,

381

molecular mass, added amount, and functionalities, can change the electrokinetic

382

potential of dispersed particles. A colloidal system with absolute zeta potential value

383

greater than 30 mV was considered stable. Na-BT formed stable dispersed suspension

384

owing to repulsive forces. The zeta potential of Na-BT in DI water in our study was

385

-32.1 mV, showing considerable stability. After adding small molecular inhibitors KCl,

386

EPTAC, and VeiBr, the zeta potential was reduced to -20.8 mV, -17.2 mV, and -8.0

387

mV, respectively (Figure 9), suggesting suppressed double electrical layers and

388

stability reduction of Na-BT colloid. PV can reverse the zeta potential to +5.3 mV,

389

+7.1 mV, and +7.5 mV, indicating the strong adsorption on the external surface of

390

Na-BT. PV can adsorb on Na-BT, and form multilayers by electrostatic interaction.

391

On one hand, PV encapsulates the Na-BT particle together. On the other hand, the

392

polymer might bridge among several Na-BT particles and form Na-BT aggregates.

393

The zeta potential measurement might explain the recovery percentage decrease when

394

the amount of PV-2 and PV-3 increases from 1.0 wt.% to 2.0 wt.% that adding too

395

much positive polymer can convert the surface negative potential of Na-BT and


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

396

prompt the dispersion of Na-BT on the contrary.

397

The phenomena in Figure 3 can be explained as follows: numerous pores are in the

398

Na-BT pellet, either pure water or small molecule solutions would enter the interior

399

by capillarity and diffusion. In pure water, the interlayer and interparticle space would

400

swell and expand; thus, the bulk volume increases. Actually, the mechanical

401

properties have been minimized and the pellet was easily dispersed by an external

402

force. Small molecular inhibitors suppress double electron layers, enter the interlayer

403

space, repel the water, and cause the shrinkage of local region and the split of Na-BT

404

pellet. The split particles, formed in a small molecular inhibitor solution, are

405

extremely hard. The polymeric ionic liquid can encapsulate the Na-BT pellet, prevent

406

the water from entering the pellet, and offer the pellet some mechanical integrity.

407

Therefore, the primary shape of the pellet is maintained. However, the slight increase

408

in the volume infers that the polymer is unable to completely inhibit swelling of

409

Na-BT pellet.

410

The morphology of Na-BT can be observed by an electron microscopy. As shown in

411

Figure 10, pure Na-BT suspension displayed quite homogeneously distributed

412

particles (Figures 10a and 10h). Moreover, adding small molecular inhibitors

413

including KCl, EPTAC, and VeiBr can induce the aggregation of Na-BT. Na-BT is

414

distributed inhomogeneously, but has not formed stable aggregate under the inhibition

415

function of KCl, whereas EPTAC and VeiBr prompted the formation of Na-BT

416

aggregates, and the size was sufficiently large to settle (Figure 10i). The aggregate


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417

size of VeiBr inhibited Na-BT is larger than that of the EPTAC. This phenomenon

418

indicated that the interactive force between the VeiBr inhibitor and Na-BT is the

419

strongest. After adding PV, Na-BT was encapsulated and turned into settled irregular

420

aggregates. As the length of polymer chain increases, the number of Na-BT particles

421

linked by PV increased and the aggregates settled down easily, as shown in Figure 10i.

422

The variation of particle size (Figure 11 and Table 2) accorded with the result from

423

the electron microscopy. For example, the median diameter of the particles (D50)

424

increases from 26.375 µm to 475.968 µm depending on the inhibitor species. The

425

particle-size distribution and zeta potential results reflect inhibitor destabilize Na-BT

426

suspension and prompt aggregation, sedimentation, beneficial for stability of Na-BT

427

pellet and shale.

428

Ionic liquid and polymeric ionic liquid are typical organic electrolytes and

429

polyelectrolytes. Ionic liquid can exchange with sodium cations, be electrostatically

430

adsorbed by Na-BT, and repel water molecule from Na-BT interlayer space. Different

431

from the typical temporary inhibitor KCl, VeiBr might still be adsorbed by clay,

432

stabilize shale, and used as permanent inhibitor, when the drilling fluids is displaced

433

by fresh water.20, 31 Moreover, VeiBr displayed excellent thermal stability. Therefore,

434

ionic liquid is promising to replace KCl as monomeric inhibitor. Polymeric ionic

435

liquid can adsorb on the surface of Na-BT particles by multiple adsorption sites with a

436

few molecules stepping into Na-BT interlayer space, depending on the molecular

437

weight. Therefore, polymeric ionic liquid can be developed as chemical sealing


Energy & Fuels

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438

additives to prevent water ingress into shale by encapsulating effect. PV in our study,

439

an oligomeric ionic liquid (PV-1) or polymeric ionic liquid with not long chains (PV-2

440

and PV-3), can provide permanent clay stabilization by preventing water from

441

entering the fractures and pores and excluding water molecules from entering and

442

hydrating the clay simultaneously. Ionic liquid and polymeric ionic liquid

443

combinations also show synergetic inhibition effects according to the experiments.

444

This combination can be developed as potential shale swelling inhibition formulation

445

in the future.

446

4. CONCLUSIONS

447

The ionic liquid VeiBr and the homopolymer PV can be developed as inhibitors in

448

drilling fluids to inhibit the hydration, swelling, and dispersion of Na-BT. Compared

449

with KCl and EPTAC, small molecule VeiBr and PV displayed better thermal stability,

450

beneficial to high-temperature drilling. Furthermore, VeiBr showed superior ability in

451

inhibiting hydration, minimizing linear swelling degree, abating dispersion of Na-BT

452

suspension, and increasing recovery of shale cuttings. By polymerization method, PV

453

can encapsulate bentonite by multi adsorption sites, and can be used as sealing

454

additive to prevent water ingress into shale. VeiBr suppresses the double electrical

455

layers, adsorbs on Na-BT, enters the interlayer space, and impedes the crystalline

456

swelling of Na-BT. The major part of PV strongly adsorbs on the surface of Na-BT,

457

bridges among Na-BT particles, and encapsulates them. Moreover, some PV

458

molecules enter the interlayer space, replace the hydrated cations, and finally prevent


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459

the dispersion of Na-BT. Ionic liquid and polymeric ionic liquid combinations might

460

be developed as highly-effective inhibitors in the future.


Energy & Fuels

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ACKNOWLEDGEMENTS This work was supported by the National Science Foundation of China (grant No. 51604290); and startup foundation of China University of Petroleum (Beijing) (grant No. 2462015YJRC023).

REFERENCES (1) Simpson, J. P.; Dearing, H. L.; Salisbury, D. P. Downhole Simulation Cell Shows Unexpected Effects of Shale Hydration on Borehole Wall (includes associated papers 19519 and 19885 ). SPE Drilling Engineering 1989, 4 (01), SPE-17202-PA. (2) Simpson, J. P.; Walker, T. O.; Jiang, G. Z. Environmentally Acceptable Water-Base Mud Can Prevent Shale Hydration and Maintain Borehole Stability. SPE Drill. Completion 1995, 10 (04), SPE-27496-PA. (3) Zhou, Z.; Gunter, W. D.; Kadatz, B.; Cameron, S. Effect Of Clay Swelling On Reservoir Quality. J. Can. Pet. Technol. 1996, 35 (07), PETSOC-96-07-02. (4) Sherwood, J. D. A Model for the Flow of Water and Ions into Swelling Shale. Langmuir 1994, 10 (7), 2480-2486. (5) Bailey, L.; Keall, M.; Audibert, A.; Lecourtier, J. Effect of Clay/Polymer Interactions on Shale Stabilization during Drilling. Langmuir 1994, 10 (5), 1544-1549. (6) Yuan, W.; Li, X.; Pan, Z.; Connell, L. D.; Li, S.; He, J. Experimental Investigation of Interactions between Water and a Lower Silurian Chinese Shale. Energy Fuels 2014, 28 (8), 4925-4933.


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(7) Luckham, P. F.; Rossi, S. The colloidal and rheological properties of bentonite suspensions. Adv. Colloid Interface Sci. 1999, 82 (1–3), 43-92. (8) Laird, D. A. Influence of layer charge on swelling of smectites. Appl. Clay Sci. 2006, 34 (1-4), 74-87. (9) Lantenois, S.; Nedellec, Y.; Prélot, B.; Zajac, J.; Muller, F.; Douillard, J. M. Thermodynamic assessment of the variation of the surface areas of two synthetic swelling clays during adsorption of water. J. Colloid Interface Sci. 2007, 316 (2), 1003-1011. (10) Anderson, R. L.; Ratcliffe, I.; Greenwell, H. C.; Williams, P. A.; Cliffe, S.; Coveney, P. V. Clay swelling — A challenge in the oilfield. Earth-Sci. Rev. 2010, 98 (3–4), 201-216. (11) Salles, F.; Bildstein, O.; Douillard, J. M.; Jullien, M.; Raynal, J.; Van Damme, H. On the Cation Dependence of Interlamellar and Interparticular Water and Swelling in Smectite Clays. Langmuir 2010, 26 (7), 5028-5037. (12) Steiger, R. P. Fundamentals and Use of Potassium/Polymer Drilling Fluids To Minimize Drilling and Completion Problems Associated With Hydratable Clays. J. Pet. Technol. 1982, 34 (08), SPE-10100-PA. (13) Sharma, S. K.; Kachari, J., Title : Use of KCl -Polymer Clouding Out Polyol Drilling Fluid in combating high pressure in deep exploratory wells of Assam Field :A case study. SPE Oil and Gas India Conference and Exhibition: Mumbai, India, Jan 20-22, 2010; pp SPE-128849-MS. (14) Xuan, Y.; Jiang, G. C.; Li, Y. Y.; Yang, L. L.; Zhang, X. M. Biodegradable oligo


Energy & Fuels

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(poly-L-lysine) as a high-performance hydration inhibitor for shale. Rsc Adv. 2015, 5 (103), 84947-84958. (15) Zhong, H. Y.; Qiu, Z. S.; Zhang, D. M.; Tang, Z. C.; Huang, W. A.; Wang, W. J. Inhibiting shale hydration and dispersion with amine-terminated polyamidoamine dendrimers. J. Nat. Gas. Sci. Eng. 2016, 28, 52-60. (16) Patel, A.; Stamatakis, S.; Young, S.; Friedheim, J., Advances in Inhibitive Water-Based Drilling Fluids—Can They Replace Oil-Based Muds? International Symposium on Oilfield Chemistry, Houston: Texas, U.S.A., Feb 28- March 2, 2007; pp SPE-106476-MS. (17) Suter, J. L.; Coveney, P. V.; Anderson, R. L.; Greenwell, H. C.; Cliffe, S. Rule based design of clay-swelling inhibitors. Energ Environ. Sci. 2011, 4 (11), 4572-4586. (18) Patel, A. D., Design and Development of Quaternary Amine Compounds: Shale Inhibition With Improved Environmental Profile. International Symposium on Oilfield Chemistry: Houston, Texas, U.S.A., Apr. 20-22, 2009; pp SPE-121737-MS. (19) Hallett, J. P.; Welton, T. Room-Temperature Ionic Liquids: Solvents for Synthesis and Catalysis. 2. Chem. Rev. 2011, 111 (5), 3508-3576. (20) Berry, S. L.; Boles, J. L.; Brannon, H. D.; Beall, B. B. Performance evaluation of ionic liquids as a clay stabilizer and shale inhibitor. SPE International Symposium and Exhibition on Formation Damage Control: Lafayette, Louisiana, U.S.A., Feb. 13-15; pp SPE-112540-MS (21) Chen, H. J.; Jepson, W. P.; Hong, T., High Temperature Corrosion Inhibition Performance of Imidazoline and Amide. Corrosion 2000: Orlando, Florida, U.S.A.,


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Mar. 26-31, 2000; pp NACE-00035. (22) Carrier, B.; Wang, L.; Vandamme, M.; Pellenq, R. J. M.; Bornert, M.; Tanguy, A.; Van Damme, H. ESEM Study of the Humidity-Induced Swelling of Clay Film. Langmuir 2013, 29 (41), 12823-12833. (23) Warr, L.; Berger, J. Hydration of bentonite in natural waters: Application of “confined volume” wet-cell X-ray diffractometry. Phys. Chem. Earth, Parts A/B/C 2007, 32 (1–7), 247-258. (24) Bianchi, A. E.; Fernandez, M.; Pantanetti, M.; Vina, R.; Torriani, I.; Sanchez, R. M.

T.;

Punte,

G.

ODTMA(+)

and

HDTMA(+)

organo-montmorillonites

characterization: New insight by WAXS, SAXS and surface charge. Appl. Clay Sci. 2013, 83-84, 280-285. (25) Nasser, M. S.; Onaizi, S. A.; Hussein, I. A.; Saad, M. A.; Al-Marri, M. J.; Benamor, A. Intercalation of ionic liquids into bentonite: Swelling and rheological behaviors. Colloids Surf., A 2016, 507, 141-151. (26) Shaplov, A. S.; Ponkratov, D. O.; Vygodskii, Y. S. Poly(ionic liquid)s: Synthesis, properties, and application. Polym. Sci., Ser. B 2016, 58 (2), 73-142. (27) Yuan, J. Y.; Antonietti, M. Poly(ionic liquid) Latexes Prepared by Dispersion Polymerization of Ionic Liquid Monomers. Macromolecules 2011, 44 (4), 744-750. (28) Ghiaci, M.; Aghabarari, B.; Gil, A. Production of biodiesel by esterification of natural fatty acids over modified organoclay catalysts. Fuel 2011, 90 (11), 3382-3389. (29) Ferrage, E.; Lanson, B.; Sakharov, B. A.; Drits, V. A. Investigation of smectite hydration properties by modeling experimental X-ray diffraction patterns: Part I.


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Montmorillonite hydration properties. Am. Mineral. 2005, 90 (8-9), 1358-1374. (30) Anderson, R. L.; Ratcliffe, I.; Greenwell, H. C.; Williams, P. A.; Cliffe, S.; Coveney, P. V. Clay swelling - A challenge in the oilfield. Earth-Sci. Rev. 2010, 98 (3-4), 201-216. (31) Gomez, S. L.; Patel, A., Shale Inhibition: What Works? SPE International Symposium on Oilfield Chemistry: The Woodlands, Texas, U.S.A., Apr. 8-10, 2013; pp SPE-164108-MS. (32) Kadaster, A. G.; Guild, G. J.; Hanni, G. L.; Schmidt, D. D. Field Applications of PHPA Muds. 7 (03), SPE-19531-PA. (33) Kim, N. H.; Malhotra, S. V.; Xanthos, M. Modification of cationic nanoclays with ionic liquids. Microporous mesoporous mater. 2006, 96 (1), 29-35.


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Energy & Fuels

Table 1. Amounts of inhibitors into Na-BT. Mass lossa Total weight lossb % % KCl 1.341 8.066 EPTAC 10.281 16.939 VeiBr 7.098 14.394 PV-1 18.909 26.017 PV-2 20.353 27.411 PV-3 18.003 25.235 was calculated by the difference between Na-BT/inhibitor and Na-BT at

Entry

Inhibitor

1 2 3 4 5 6 a Mass loss 700 °C. b Total weight loss was calculated by the difference of weight at 140 ºC and 700 °C.


Energy & Fuels

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Table 2. Particle size distribution of Na-BT in different inhibitor aqueous solutions. Da10 Db50 Dc90 µm µm µm blank 8.905 26.375 51.723 KCl 19.365 39.094 71.437 EPTAC 50.094 122.417 237.930 VeiBr 47.838 135.655 291.712 PV-1 49.056 198.004 600.087 PV-2 78.750 356.357 1160.850 PV-3 103.282 475.968 1393.071 a D10 is the diameter at which 10% of the sample’s mass is comprised of particles with a diameter less than this value. b D50 is the diameter that 50% of a sample’s mass is smaller than and 50% of a sample’s mass is larger than. D50 is also known as the “mass median diameter”. c D90 is the diameter at which 90% of the sample’s mass is comprised of particles with a diameter less than this value. Inhibitor


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Energy & Fuels

Captions Scheme 1. Systematic diagram for homopolymer of VeiBr. Figure 1. NMR spectra of VeiBr (a) and PVeiBr (b). Figure 2. Thermal stability of pure Na-BT and Na-BT/inhibitor composites (a) and pure organic inhibitors (b). Figure 3. Morphology of Na-BT pellet immersed in pure water and inhibitor solutions for 5 minutes: (a) pure water, (b) 2.0 wt.% KCl, (c) 2.0 wt.% EPTAC, (d) 2.0 wt.% VeiBr, (e) 2.0 wt.% PV-1, (f) 2.0 wt.% PV-2, (g) 2.0 wt.% PV-3. (a1)-(g1) and (a2)-(g2) are those of (a)-(g) after immersing for 24 h and 240 h. Figure 4. Na-BT inhibition test by comparing the apparent viscosity (a) and yield point (b) of inhibitor aqueous solutions, and base Na-BT-WDFs as a function of Na-BT content. Figure 5. Linear swelling curves of the Na-BT in DI water, KCl, JAY, VeiBr, and PV. The concentration of all samples is 2.0 wt.%. Figure 6. Linear swelling curves of the Na-BT in VeiBr (a), PV-1 (b), PV-3 (c), and PV-3 (d) at 0.25 wt.%, 1.0 wt.%, 1.5 wt.%, 2.0 wt.%, respectively. Figure 7. Recovery percentages of shale after being hot-rolled in inhibitor solutions at a concentration of 1.0 wt.% (a) and 2.0 wt.% (b) at 120 °C for 16 h. Figure 8. XRD patterns of Na-BT wet samples with different inhibitors (a), Na-BT dry samples with different inhibitors (b), and Na-BT dry samples with VeiBr at different concentrations (c). Figure 9. Zeta potential measurement of Na-BT in various inhibitor systems.


Energy & Fuels

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Figure 10. Electron microscopy images of Na-BT suspension in DI water (a) and different inhibitor aqueous solutions: (b) KCl; (c) EPTAC; (d) VeiBr; (e) PV-1; (f) PV-2; (g) PV-3 observed at a total magnification of 40. Figure 11. Particle-size distribution of Na-BT in different inhibitor aqueous solutions.


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Energy & Fuels

Scheme 1. Systematic diagram for homopolymer of VeiBr.


Energy & Fuels

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Page 34 of 45

b

a 10

8

6

4

2

0

δ (ppm)

Figure 1. 1H NMR spectra of VeiBr (a) and PVeiBr (b).


Page 35 of 45

100

Weight percentage (%)

(a) 95 90 85 BT BT/KCl BT/EPTAC BT/VeiBr BT/PV-1 BT/PV-2 BT/PV-3

80 75 70

100

200

300

400

500

600

700

Temperature (°C)

100

(b) Weight percentage (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

EPTAC VeiBr PV-1 PV-2 PV-3

80

60

40

20

0 100

200

300

400

500

600

700

Temperature (°C)

Figure 2. Thermal stability of pure BT and BT/inhibitor composites (a) and pure organic inhibitors (b).


Energy & Fuels

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Figure 3. Morphology of BT pellet immersed in pure water and inhibitor solutions for 5 minutes: (a) pure water, (b) 2.0 wt.% KCl, (c) 2.0 wt.% EPTAC, (d) 2.0 wt.% VeiBr, (e) 2.0 wt.% PV-1, (f) 2.0 wt.% PV-2, (g) 2.0 wt.% PV-3. (a1)-(g1) and (a2)-(g2) are those of (a)-(g) after immersing for 24 h and 240 h.


Page 36 of 45

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160

pure BT KCl EPTAC VeiBr PV-1 PV-2 PV-3

Apparent viscosity (mPa.s)

(a) 140 120 100 80 60 40 20 0

4% 8% 12% 16% 20% 24% 28% 32% 36% 40%

Concentration (w/v)

60

pure BT KCl EPTAC VeiBr PV-1 PV-2 PV-3

(b) Yeild point (Pa)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

40

20

0 8%

16%

24%

32%

40%

Concentration (w/V)

Figure 4. BT inhibition test by comparing the apparent viscosity (a) and yield point (b) of inhibitor aqueous solutions, and base BT-WDFs as a function of BT content.


Energy & Fuels

6

Linear swelling height (mm)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 45

Pure BT KCl EPTAC VeiBr PV-1 PV-2 PV-3

5 4 3 2 1 0 0

5

10

15

20

25

Time (h)

Figure 5. Linear swelling curves of the BT in DI water, KCl, JAY, VeiBr, and PV. The concentration of all samples is 2.0 wt.%..



6

0.25 wt% 0.5 wt% 1.0 wt% 2.0 wt% DI water

5 4

(a)

3 2 1

6

0


5 4

(b)

3 2 1 0

0

5

10

15

20

25

0

5

Time (h)

6


5 4

10

15

20

25

Time (h)

(c)

3 2 1


6


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels


Page 39 of 45


5 4

(d)

3 2 1 0

0 0

5

10

15

20

25

0

5

10

15

20

25

Time (h)

Time (h)

Figure 6. Linear swelling curves of the BT in VeiBr (a), PV-1 (b), PV-3 (c), and PV-3 (d) at 0.25 wt.%, 1.0 wt.%, 1.5 wt.%, 2.0 wt.%, respectively.


Energy & Fuels

Shale recovery percentage (wt%)

70

(a) 60 50 40 30 20 10 0

DI W

ate r

KC

l

Ve EP i Br MT C

PV -1

PV -2

PV -3

KC

l

Ve EP i Br MT C

PV -1

PV -2

PV -3

80

Shale recovery percentage (wt%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 40 of 45

(b) 70 60 50 40 30 20 10 0

DI W

ate r

Figure 7. Recovery percentages of shale after being hot-rolled in inhibitor solutions at a concentration of 1.0 wt.% (a) and 2.0 wt.% (b) at 120 °C for 16 h.


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Energy & Fuels

d=17.24 Å

PV-3

d=17.24 Å PV-2 PV-1

d=15.27 Å d=13.67 Å

VeiBr d=14.34 Å EPMTC d=14.75 Å KCl

d=18.80 Å, 15.87 Å

blank 4

6

8

10

12

14

2θ (°)

d>24.10 Å

PV-3

d>24.10 Å d=24.10 Å

PV-2 d=13.77 Å PV-1 d=13.74 Å

VeiBr

d=13.63 Å

EPTAC

d=12.01 Å

KCl

d=12.55 Å 4

6

MMT 8

10

12

14

2θ θ (°)

d=13.74 Å

2.0 wt% d=13.64 Å

1.5 wt%

d=13.63 Å

1.0 wt%

d=13.34 Å

0.5 wt% d=13.18 Å

0.2 wt% d=12.55 Å 4

6

8

0 wt% 10

12

14

2θ (°)

Figure 8. XRD patterns of BT wet samples with different inhibitors (a), BT dry samples with different inhibitors (b), and BT dry samples with VeiBr at different concentrations (c).


Energy & Fuels

40 30

ei Br

PV -3

PV -2

PV -1

V

EP TA

0 -10

K Cl

10

C

20

D Iw at er

Zeta potential (mV)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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-20 -30 -40

Figure 9. Zeta potential measurement of Na-BT in various inhibitor systems.


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Energy & Fuels

Figure 10. Electron microscopy images of Na-BT suspension in DI water (a) and different inhibitor aqueous solutions: (b) KCl; (c) EPTAC; (d) VeiBr; (e) PV-1; (f) PV-2; (g) PV-3 observed at a total magnification of 40.


Energy & Fuels

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DI water KCL EPTAC VeiBr PV-1 PV-2 PV-3

10 8 6 4 2 0 1

10

100

1000

Size (µ µm)

Figure 11. Particle size distribution of Na-BT in different inhibitor aqueous solutions.


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Energy & Fuels

Immersing in DI water would lead to the swelling and dispersion of Na-BT pellet. This process can be effectively inhibited by adding the ionic liquid 1-vinyl-3-ethylimidazolium bromide (VeiBr) monomer and its homopolymer. By comparison, the latter can keep original shape and exhibits better inhibition performance. 49x34mm (600 x 600 DPI)


Application of Ionic Liquid and Polymeric Ionic Liquid as Shale

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