Investigation of Hydrate Agglomeration and Plugging Mechanism in

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Investigation of Hydrate Agglomeration and Plugging Mechanism in Low-Wax-Content Water-in-Oil Emulsion Systems Yang Liu, Bohui Shi, Lin Ding, Yu Yong, Ye Zhang, Qianli Ma, xiaofang Lv, Shangfei Song, Juheng Yang, Wei Wang, and Jing Gong Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01323 • Publication Date (Web): 27 Aug 2018 Downloaded from http://pubs.acs.org on August 28, 2018

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Energy & Fuels

1

Investigation of Hydrate Agglomeration and Plugging

2

Mechanism in Low-Wax-Content Water-in-Oil Emulsion

3

Systems

4

Yang Liu1, Bohui Shi1*, Lin Ding1, Yu Yong1, Ye Zhang1, Qianli Ma1, Xiaofang Lv2,

5

Shangfei Song1, Juheng Yang1,3, Wei Wang1, Jing Gong1*

6

1

7

Engineering/Beijing Key Laboratory of Urban Oil and Gas Distribution Technology, China

8

University of Petroleum-Beijing, Beijing 102249, People’s Republic of China

9

2

National Engineering Laboratory for Pipeline Safety/MOE Key Laboratory of Petroleum

Jiangsu Key Laboratory of Oil and Gas Storage and Transportation Technology,

10

Changzhou University, Changzhou, Jiangsu 213016, People’s Republic of China

11

3

12

ABSTRACT. Pipeline blockage caused by hydrates and wax in subsea pipelines is a

13

major hazard for flow assurance in the petroleum industry. When hydrates and wax

14

coexist in a flow system, the plugging risk is more severe. The effects of wax on

15

hydrate formation, agglomeration process, flow properties and plugging mechanisms

16

were studied in a high-pressure flow loop using water-in-oil (w/o) emulsion systems.

17

The flow properties of the system with the presence of wax were entirely different

18

from those of the system without wax under the same experimental conditions.

19

Three types of plugging were observed in the flow loop: rapid plugging, transition

PetroChina International Co., Ltd., Beijing 100033, People’s Republic of China

1

ACS Paragon Plus Environment

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plugging and gradual plugging. The interaction relationships between wax crystals,

21

water droplets and hydrate particles and the formation of wax-hydrate aggregates

22

were proposed based on the particle video measurement (PVM) probe observation

23

and the analysis of the fluid viscosity. The mechanisms of different plugging

24

scenarios were presented, which were highly correlated with the temperature and

25

initial flow rate. The presence of wax would impact on the agglomeration process of

26

hydrate particles leading to a catastrophic decrease in the transportation ability and

27

an extremely high plugging risk after hydrate formation in the pipeline.

28

KEYWORDS: Flow assurance; Wax; Hydrate; Agglomeration; Deposition

29

1. INTRODUCTION

30

With the gradual depletion of onshore and offshore resources, deep-water fields

31

and unconventional resources (shale gas, hydrates, etc.) have become the focus of

32

oil and gas development1-4. Research on the naturally occurring hydrate resources

33

has attracted significant attention from the academic and industrial fields, because

34

their enormous available energy will benefit mankind if they can be explored using

35

appropriate exploration methods4. Hydrates are a double-edged sword because they

36

are also one of the major solids formed in the transportation system in the subsea5-6.

37

In addition, they are one of the major hazards for flow assurance especially when

38

both hydrates and wax crystals are present in the flow system.

39

Natural gas hydrates are complex ice-like crystalline solids composed of natural

40

gas (guest molecules) and water (host molecules), which form under high pressure 2


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and low temperature7. Wax molecules, consisting primarily of alkanes, will

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precipitate from the oil phase once the temperature is below the wax appearance

43

temperature (WAT)8. Hydrate formation and wax deposition will cause the loss of

44

production capacity and increase the risk of pipeline plugging9-13. A series of control

45

methods and treatments has been presented by the academic and engineering fields

46

to solve hydrate plugging and wax deposition problems. For hydrate-associated

47

problems, hydrate risk management with the injection of low-dosage hydrate

48

inhibitors

49

anti-agglomerates (AAs), has gained greater interest compared with the traditional

50

methods such as heat insulation or thermodynamic inhibitors (THIs) injection with

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their high cost and environmental impact2,5,7. With the application of hydrate risk

52

management, the induction time of hydrate is prolonged by KHIs, which aim to

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provide enough time for production liquids to reach platforms or processing

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facilities14; or hydrates are allowed to form while the agglomeration of hydrate

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particles is reduced by AAs, which aim to maintain good transportability of the

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fluid15. Unlike the stochastic and rapid plugging due to hydrate deposition, plugging

57

due to wax deposition is much slower. Researchers16-18 have concentrated on the

58

prediction model of wax deposition, which aims to obtain an optimum pigging

59

period.

(LDHIs),

including

kinetic

hydrate

inhibitors

(KHIs)

and

60

There are many independent studies on hydrate formation and wax deposition.

61

There are only limited literature reports of the effects of the coexistence of wax and

62

hydrates on pipeline blockage tendency and risk by rocking cell6,19, autoclave20-22 or 3


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rheometer23. Gao6 showed that when wax and hydrates coexisted in the rocking cell,

64

the deposits on the cell wall were probably a mixture of wax and hydrate particles.

65

Ji24 and Mohammadi et al.20 proposed that the precipitation of wax could provide the

66

necessary nucleation sites for hydrate formation and might promote the formation of

67

hydrates by reducing the required subcooling. Both Zheng et al.21 and Shi et al.22

68

found that the hydrate induction time increased with increasing wax content from

69

the experiments carried out in autoclaves. Oliveira et al.23 proposed that when

70

hydrates formed in a water-in-crude oil system, the pipeline plugging tendency

71

increased due to an agglomeration process between hydrate particles or even hydrate

72

particles and wax. These experimental studies conducted in the rocking cells or

73

autoclaves have revealed that the simultaneous formation of wax and hydrates can

74

synergistically escalate their precipitation and deposition, promoting the possibility

75

of pipeline blockage.

76

A w/o emulsion is reported to be the most prevalent type of all the emulsion types

77

(i.e., oil-in-water, water-in-oil-in-water, etc.) in multiphase gathering flow

78

transportation systems including oil, gas, water and solids, because of the presence

79

of natural surfactant and turbulence of pipe-flow 25-26. Hydrates usually form on

80

oil-water interfaces in w/o systems under appropriate conditions7,27. Wax crystals are

81

prone to be adsorbed on oil-water interfaces8,23,28,29 because of the synergistic effect

82

between wax and surfactants28. Therefore, it is reasonable to speculate that wax

83

crystals have some effects on the interfacial hydrate formation and aggregation

84

process especially for volatile waxy oil fields6,9,19, which will enhance the risk of 4


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hydrate plugging and reduce the ability of the pipeline to maintain flow. The studies

86

of hydrate-slurry viscosity provide some evidence to prove this speculation10,30.

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Camargo and Palermo31 noted that the particle agglomeration produced by cohesive

88

forces between hydrate particles was the reason for the increment in fluid viscosity.

89

Otherwise, the collision of a hydrate particle with another water droplet was

90

observed by Aman et al.32 using a micromechanical force (MMF) apparatus, called

91

sintering, also leading to the increase of aggregates in the fluid. In addition, attention

92

should be paid to the effects of surfactants on cohesive force. Brown et al.33 found

93

that the addition of a surfactant would influence the strength of the hydrate shell and

94

reduce the cohesive force. Thus, it is more definite to infer that wax crystals

95

adsorbed at the oil-water interface do impact on the hydrate formation and

96

agglomeration process. However, little work on this interaction between hydrates

97

and wax has been reported.

98

The studies on plugging phenomena in a flow system are important to the

99

investigation of hydrate agglomeration and plugging mechanisms in the presence of

100

wax in w/o systems. Zerpa et al.34 proposed that hydrate plugging could be defined

101

in oil-dominated systems where the hydrate volume fraction exceeded 30% and the

102

viscosity of the oil phase exceeded 1000 mPa·s. Even though hydrates form in a

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flow system with a small mass fraction of 5% ‒ 6%, a blockage was observed in a

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high-pressure flow loop in a natural gas + diesel oil + water system with a 30%

105

water cut13. Hydrate particles/aggregates would deposit on the pipe wall and reduce

106

the flow diameter to increase the risk of plugging in the pipeline10,30,35,36 as long as 5


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the adhesive force between hydrate particles/aggregates and the pipe wall is higher

108

than the flow shear stress37. Therefore, the flow rate is a critical parameter to affect

109

hydrate deposition and bedding. Grasso38 proposed that when the velocity of the

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flow system was lower than the critical bedding velocity, hydrate particles would

111

form a stationary bed, which resulted in a reduction of the flow diameter. Zhao et

112

al.39 proposed that large hydrate chunks would accumulate on the wall of their

113

rocking cell, because the oscillation of the cell was insufficient to keep the chunks

114

suspended in the oil phase. In addition, a four-step plugging mechanism for

115

oil-dominated or w/o system has been proposed by Turner40 and developed by

116

Davies et al.41: (i) w/o system with dissolved gas forms due to flow shear; (ii)

117

hydrate nuclei appear at the oil-water interface, and the hydrate shell grows at the

118

surface of water droplets; (iii) due to the contact or collision of hydrate particles,

119

hydrate aggregates form with the strength of the cohesive force31-32; (iv) the

120

transportability of the system declines or a jamming-type plugging30 occurs,

121

resulting from further aggregation process. In addition, the influence of wax deposits

122

and surfactants on hydrate deposition should also be considered. Erfani et al.42

123

proposed that some surfactants may reduce the interfacial tension of the liquid-liquid

124

interface and the adhesive force of hydrate particles.

125

In this work, experiments were conducted using w/o emulsion systems composed

126

of 80 vol.% diesel oil with 0.75 wt.% wax and 20 vol.% deionized water with 1 wt.%

127

AA. The effects of wax on hydrate formation and the agglomeration process, flow

128

properties and plugging mechanisms in a high-pressure flow loop were investigated. 6


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Three types of plugging were observed in the flow loop. Based on the PVM probe

130

observation and the analysis of the fluid viscosity, interaction relationships between

131

wax crystals, water droplets and hydrate particles, as well as the mechanisms of

132

different plugging scenarios were presented, which were in high correlation with the

133

temperature and the initial flow rate. The presence of wax would impact on the

134

agglomeration process of hydrate particles leading to a catastrophic decrease in the

135

transportation ability and an extremely high plugging risk after hydrate formation in

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the pipeline.

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2. MATERIALS AND METHODS

138

2.1. Materials. The materials used in the experiments include deionized water,

139

natural gas, diesel oil, a paraffin mixture and AA, detailed information about which

140

is listed in Table 1. The carbon number of the paraffin mixture ranges from C28 to

141

C41 28. A type of combined AA provided by the Chemical Engineering Department in

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the China University of Petroleum-Beijing is a mixture of sorbitan monolaurate

143

(Span 20) and esters polymer43,44. Span 20 serves as the emulsifier45, and the

144

polymer works as the effective anti-agglomerate. With the help of High Temperature

145

Gas Chromatography (model 7890a, Agilent Technologies), the composition of

146

natural gas is given in Table 2.

147

Table 1. Detailed information for experimental materials Materials Natural gas

Source

Density (20 °C, g·cm-3)

Viscosity (20 °C, mPa·s)

--

--

0.9928

0.93

Shanjing Natural Gas Pipeline of China

Deionized

ELGA OPTION-S 7 (ELGA

water

LabWater, UK) 7


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Diesel oil

SINOPEC filling station (Beijing, China)

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0.8199

2.69

1.0580

--

0.9545

--

~ 0.91

--

Tianjin Guangfu Fine Span 20

Chemical Research Institute (Tianjin, China) China University of

Esters polymer

Petroleum-Beijing (Beijing,

Paraffin

Daqing Petrochemical

mixture (wax

Branch Company (Daqing,

solids)

China)

China)

148

Table 2. The composition of natural gas Composition N2 CO CO2 C1 C2

Mol % 1.53 2.05 0.89 89.02 3.07

Composition C3 iC4 iC5 nC6+ --

Mol % 3.06 0.33 0.04 0.01 --

149

2.2. Apparatus for the flow experiments. Flow experiments were conducted

150

in a high-pressure flow loop constructed in China University of Petroleum-Beijing,

151

as shown in Figure 1. The loop is 30-m long with a 25.4-mm internal diameter. The

152

design pressure is 150 bar, which is supplied by two high-pressure gas cylinders

153

with one in operation and one in standby. The design temperature ranges from -20

154

°C to 100 °C, which is jacketed by four Julabo water baths. A separator with a

155

volume of 220 L is used to provide the gas-liquid mixture space. The flow in the

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loop is sustained by a magnetic centrifugal pump with flow rate ranges from 0 kg·h-1

157

to 1900 kg·h-1. The following parameters: pressure, pressure drop, flow rate and

158

density, are acquired by the sensors (Endress-Hauser Corporation) and have the

159

precision of 0.1 bar, 0.1 kPa, 0.1 kg·h-1 and 0.1 kg·m-3, respectively. Temperatures

160

are measured by platinum resistance thermometers (Kunlun Gongkong Corporation)

8


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with a precision of 0.1 °C. A Focused Beam Reflectance Measurement (FBRM)

162

probe (model D600X, Mettler-Toledo Corporation) and a PVM probe (model V819,

163

Mettler-Toledo Corporation) are installed at the inlet of the flow loop, which can

164

help to study the microscopic characteristics and behaviors of water droplets and

165

hydrate particles.

166 167

Figure 1. Schematic diagram of the high-pressure hydrate flow loop

168

2.3. Procedures for the flow experiments. Water-in-oil systems composed of

169

80 vol.% diesel oil and 20 vol.% deionized water with 1.0 wt.% AA were used to

170

perform the flow experiments. The experiment with no wax added was carried out to

171

be a comparative test for the other experiments with 0.75 wt.% wax addition. Three

172

initial flow rates (1120, 1400 and 1640 kg·h-1) and four target temperatures of water 9


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bath (-1, 1, 3 and 5 °C) were selected. The target temperature of the water bath is

174

simplified as “water bath temperature”36 in the following discussion. The specific

175

different experimental conditions are listed in Table 3. In particular, Exp.2-1 and

176

Exp.3-1 were performed to verify the reproducibility of flow experiments. The water

177

cut is defined as the ratio of water volume to the total liquid volume. AA

178

concentration is defined as the mass fraction of AA to water. Wax content is defined

179

as the weight fraction of wax to diesel oil under 20 °C. A specific procedure for

180

Exp.2 is described as follows:

181

1.

182 183

Evacuate the loop to -1.0 bar using a vacuum pump to eliminate the influence of air.

2.

Add 245.99 g wax solids (in the size of around 3 – 10 mm) into the

184

stainless-steel oil container filled with 40 L diesel, and then put the

185

container into an electric heater at 80 °C for 5 h to completely dissolve

186

these wax solids.

187

3.

188 189

Load 40 L diesel oil with dissolved wax, 10 L deionized water and 100 g AA into the separator of the loop.

4.

Start the magnetic centrifugal pump with a constant pump speed, and a

190

flow rate of 1400 kg·h-1 was reached. Set the water bath temperature to 20

191

°C. The oil and water should be circulated in the flow loop for no less than

192

24 h for sufficient emulsification.

193

5.

Inject natural gas into the separator until a pressure of 50 bar was reached

194

(20 °C). This time point was assigned as zero time. Then, start the data

195

acquisition system with 8 s recording intervals.

196

6.

Set the temperatures of the water baths to target temperature of 1.0 °C.

197

7.

When the collected data became stable or the flow rate decreased to 700

198

kg·h-1, set the temperature of the water baths to 40 °C. Maintain this

10


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temperature for no less than 4 h to eliminate the memory effect of hydrate

200

formation and to entirely dissolve any wax crystals.

201

In step-2, the complete dissolution of wax was confirmed by the following

202

visual inspection. All the liquid was poured out from the stainless-steel oil container

203

into an open bucket after heating (80 °C, 5 h). No wax solid was left in the bottom of

204

the container as well as no wax solid was observed in the bucket filled with the

205

transparent diesel. Meanwhile, 80 °C was much higher than the melting temperature

206

(40~50 °C) of the wax used in this work. Thus, all the wax can be completely

207

dissolved in the diesel and the thermal history of the wax is eliminated46.

208

In step-4, a w/o emulsion formed because the water cut of flow experiments was

209

20%36. This conclusion was made mainly based on the density measurement. The

210

density of the oil-water mixture that flowed in the loop after the circulating process

211

(24 h) under ambient pressure and 20 °C was measured as 0.8544 g·cm-3. And the

212

density of the water and diesel at 20 °C was 0.9928 g·cm-3 and 0.8199 g·cm-3,

213

respectively. Then the water cut of this oil-water mixture was determined as 0.1994

214

(19.94 vol.%). Note that 80 vol.% diesel with a lower water cut below 20 vol.%

215

cannot form an oil-in-water emulsion due to the properties of diesel and surfactant

216

used in the experiments. It was indicated that diesel was the continuous phase of the

217

oil-water mixture and a w/o emulsion was formed. And no separate water layer was

218

found by visual-window observation (e.g., Figure 2a). Additionally, the

219

emulsification state could be evaluated based on the PVM images recorded with an

220

8 s interval. The spherical and uniformly distributed water droplets36 (e.g., Figure

221

2b) were continuously observed by PVM probe for at least 2 h, indicating a good 11


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222

state. Thus, after an emulsifying process of 24 h, the oil-water mixture flowing in the

223

loop was confirmed as a w/o emulsion with a good emulsification state.

224 225

226

Table 3. The different specific experimental conditions using the same water cut, AA dosage and initial temperature of 20 °C.

a

Exp.

Wax content

Water bath

Cooling rate of water

Initial flow rates

No.

(wt.%)

temperature (°C)

bath (°C·h-1) a

(kg·h-1)

1

0

1

38.0

1400

2

0.75

1

38.0

1400

2-1

0.75

1

38.0

1400

3

0.75

3

32.7

1400

3-1

0.75

3

32.7

1400

4

0.75

5

27.3

1400

5

0.75

-1

43.8

1400

6

0.75

1

38.0

1120

7

0.75

3

32.7

1120

8

0.75

1

38.0

1640

9

0.75

3

32.7

1640

Cooling rate of water bath = (20 °C – set value)/ required time of reaching set value.

(a)

227

(b)

228 12


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Figure 2. (a) Visual observation through high-pressure visual window after sufficient emulsification process. (b) A PVM image after sufficient emulsification process.

231

2.4. Measurement of WATs. An ambient-pressure DSC (model Q20, TA

232

Instruments) is used to measure the WAT of the experimental materials. In the DSC

233

test, the oil sample with wax is cooled from 80 °C to -20 °C at a rate of 5 °C·min-1.

234

For each sample, the reproducibility was verified by repeating the experiment three

235

times. The typical thermograms are shown in Figure 3 (repeated results are shown

236

in Figure S1 in the Supporting Information). As shown in Figure 3b, the first “small”

237

exothermic peak in the DSC heat-flow diagram indicates the precipitation of the

238

additional 0.75 wt.% wax content (7.44 ± 0.8 °C), while the second “large”

239

exothermic peak represents the precipitation of the heavy ends of diesel oil (-8.39 ±

240

0.2 °C). This is similar to the situation reported by Oliveira23. The temperature when

241

first peak appears is then regarded as the WAT of diesel oil with 0.75 wt.% wax

242

content, while the temperature when second peak appears equals to the WAT of pure

243

diesel and is much lower than our experimental temperature. Thus, the heavy ends

244

of diesel oil itself have little or no influence on the added wax precipitation at the

245

experimental temperatures. (b)

(a)

246 13


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247 248

Figure 3. The DSC heat-flow diagram of: (a) diesel oil, (b) diesel oil with 0.75 wt.% wax content.

249

2.5. Determination of fluid viscosity. A w/o system containing wax under

250

different temperature can generally be divided into three states: (i) a w/o emulsion

251

(temperature > WAT), (ii) a waxy w/o emulsion (temperature < WAT) and (iii) a

252

waxy w/o emulsion with hydrate particles (below hydrate formation temperature).

253

Viscosity is one of the most significant properties of a fluid. Three methods can be

254

used to obtain the viscosity of the complex fluid: measurement by rheometer,

255

estimation by a model and inverse calculation by the pressure drop (logged by the

256

high-pressure loop).

257

As shown in Figure 4, the viscosities of the w/o emulsion containing wax were

258

measured by a rheometer (model MCR-101, Anton Paar GmbH) with different

259

shear rates and temperatures (5 °C and 20 °C) under ambient pressure. Temperature

260

of 5 °C is selected to make wax precipitate out. The results indicate that both the

261

w/o emulsion (20 °C, flow index=0.98) and the waxy w/o emulsion (5 °C, flow

262

index=0.96) shows weak shear-thinning property, because the water cut (20 vol.%)

263

and wax content (0.75 wt.%) is not high compared to the literatures47-49.

264

Additionally, Floury et al.50 found that a shear-thinning emulsion under low

265

pressure conditions would be prone to behave as Newtonian fluid under high

266

pressure. Therefore, the fluids in the flow experiments before hydrate formation

267

(w/o emulsion and the waxy w/o emulsion) can be regarded as Newtonian

268

fluids47,49,50, the viscosity of which is only subject to temperature and pressure.

269

Note that for systems with higher water cut and higher wax content, the influence 14


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of shear rates cannot be ignored. Then, the measured values using the rheometer

271

should match the flow loop conditions at specific temperatures and pressures, to

272

approach the true viscosity in the loop. An exponential correlation is used to

273

conduct pressure modification51, which is shown as Eq.(1)-Eq.(2). This method can

274

only describe the viscosity of the fluid before hydrate formation.

µm = A0e B P

275

0

A0 = 0.0233

276

1 + 0.00233 Tt

(1)

(2)

277

where µm is the measured kinematic viscosity with modifications (Pa·s); P is the

278

system pressure (bar); A0 is the viscosity measured by the rheometer, which has

279

linear relationship with the temperature51 Tt (°C) shown in Figure 5 and is regressed

280

with a coefficient of determination R2=0.988, as shown in Eq.(2); and B0 describes

281

interactions between the components in the model of liquid hydrocarbon and gas

282

molecules (bar-1).

283

The Camargo-Palermo viscosity model31 for hydrate slurries is expressed in Eq.(3)

284

through Eq.(5) by introducing Mill’s suspension viscosity model52. The hydrate

285

aggregate is considered as a porous structure2, which increases the effective volume

286

fraction of hydrates. The size of the hydrate aggregates depends on the force balance

287

between flow shear stress, which acts to reduce the size of aggregates, and the

288

cohesive force between hydrate particles, which acts to increase the size of

289

aggregates. However, Camargo’s model has not yet been reported to predict the

290

viscosity of a waxy w/o emulsion system with hydrate particles, in which special 15


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

Page 16 of 53

291

aggregates with different morphologies30 may emerge. Thus, modifications may be

292

required to improve its applicability.

293

µS = µL (1 −ψ eff )

 ψ eff  1 −   ψ max 

2

(3)

2

294

3− f   dA   ψ Fa 1 −    ( 4− f ) ψ  max d   d p   −  =0  A  3− f      dp  d d p2 µ Lγ& 1 −ψ  A   d     p  

(4)

( 3− f )

295

ψ eff

d  ≈ψ  A   dp   

(5)

296

where µS is the estimated dynamic viscosity of the suspension (Pa·s); µL is the

297

dynamic viscosity of the continuous phase (Pa·s); ψeff is the effective hydrate

298

volume fraction; ψmax is the maximum hydrate volume fraction2, ψmax=4/7; dA is the

299

diameter of the aggregates (m); dp is the diameter of the hydrate particles (m); f is

300

the fractal dimension; γ& is the shear rate (s-1); Fa is the cohesive force of hydrate

301

particles (mN·m-1), which has been estimated by Aman et al.32 and Hu et al.53; ψeff=ψ

302

if dA/dp≤1, indicating the impact of flow shear is stronger than the impact of

303

cohesive force and no aggregates form.

304

Since the pressure drop, flow rate and fluid density were acquired by the sensors,

305

inverse calculation was available to obtain the viscosity of a waxy w/o emulsion

306

with hydrate particles. Based on the transformation of the Darcy-Weisbach hydraulic

307

friction formula13, Eq.(6) is derived with the assumption that the flow diameter

308

remains constant during the whole experimental process. The greatest limitation of

16


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Energy & Fuels

309

this method is that the change in flow diameter because of solid-phase deposition

310

will produce a relatively large deviation of the results. 1

311

 ∆P D5−m  m ⋅ µc =  2−m   ρ g β LQ 

312

where µc is the calculated kinematic viscosity of the fluid (m2·s-1); ∆P is the pressure

313

drop of the flow loop (Pa); D is the flow diameter (m); L is the length of the flow

314

loop (m); g is the gravitational acceleration (g=9.8 m·s-2); β and m is determined by

315

the flow regime of the fluid (for laminar flow, β=4.15 and m=1; for hydraulically

316

smooth flow, β=0.0246 and m=0.25); Q is the flow rate (kg·s-1); and ρ is the density

317

of the fluid (kg·m-3).

(6)

318 319 320 321

Figure 4. Viscosity of w/o emulsion (20 vol.% water cut and 0.75 wt.% wax content) versus shear rate at 20 °C and 5 °C. Measured by the rheometer under ambient pressure. 20 °C > WAT > 5 °C.

17


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

Page 18 of 53

322 323 324 325

Figure 5. The relationship between viscosity and temperature obtained from the rheometer (0.75 wt.% wax content, 20 vol.% water cut, ambient pressure and shear rate of 300 s-1).

326

2.6. Determination of hydrate volume fraction. As proposed by Ding et al.54,

327

the amount of hydrate formation for the flow loop can be calculated though the

328

amount of gas consumption based on the equation of state for the real gas, which is

329

expressed as Eq.(7).

330

ng =

PV 1 g z1RT1

−

PV 2 g z2 RT2

(7)

331

where ng is the moles of gas consumption (mol); P1 is the system pressure before

332

hydrate formation (Pa); P2 is the system pressure after hydrate formation (Pa); Vg is

333

the gas volume in the separator (m3); z1 and z2 are the compressibility factors in the

334

pressure of P1 and P2 and are calculated based on Peng-Robinson equation of state

335

(PR-EoS)54; R is the gas constant (J·mol-1·K-1); T1 is the system temperature before

336

hydrate formation (K); and T2 is the system temperature after hydrate formation (K).

337

Then, the hydrate volume fraction can be obtained by Eq.(8). 18


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Energy & Fuels

338

ϕ=

(n M

+ N hyd ng M w ) ρ H n M + N hyd ng M w N hyd ng M w − VL ,i + g g g

g

ρH

(8)

ρw

339

where φ is the hydrate volume fraction; Mg is the average molar mass of natural gas

340

(kg·mol-1); Nhyd is the hydration number (for natural gas, Nhyd=5.85)7; Mw is the

341

molar mass of water (kg·mol-1); ρH and ρw are the densities of the hydrate and water

342

respectively (kg·m-3); and VL,i is the initial volume of the liquid phase (m3).

343

3. RESULTS AND DISCUSSION

344

3.1. Effects of wax on flow properties before and after hydrate formation.

345

Researchers9,20,24 have shown that the precipitation of heavy ends would have an

346

effect on the hydrate equilibrium boundary. However, according to the report from

347

Mahabadian et al.9, the effect of wax on the hydrate phase boundary was marginal.

348

Therefore, the phase equilibrium temperature of natural gas hydrate formation in

349

bulk water under different pressure is calculated by the Chen-Guo model56 without

350

consideration of the effects of wax on the hydrate equilibrium, as shown in Figure

351

6a. Further studies on the effect of wax on hydrate equilibrium should be performed

352

using a high-pressure DSC or other devices to examine hydrate dissociation

353

temperature9,57 with wax. As shown in Figure 6b, a decrease in the system pressure

354

is observed during the cooling period (setting the water bath temperature from 20 °C

355

to 1 °C for Exp.2). After hydrate formation, the temperature increases because it is

356

an exothermic process. Additionally, the subcooling degree is defined as the

357

difference between the hydrate equilibrium temperature and formation temperature. 19


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

358

For flow experiments Exp.1 ‒ Exp.9, typically a subcooling of approximately 5.0 °C

359

‒ 7.0 °C is required. As shown in Figure 7b, the deflection point of the pressure

360

drop curve indicates the onset of wax deposition, the temperature of which is

361

determined as 11.6 °C. Besides, all the temperatures of wax deposition onset of

362

other flow experiments (Exp.3-Exp.9) have been obtained and their average is

363

11.4±1.5 °C. Thus, all the flow experiments match the conditions for hydrate

364

formation temperature < temperature of wax deposition onset < hydrate equilibrium

365

temperature. In summary, wax crystals precipitate out before hydrate formation.

366

The flow properties (i.e., pressure drop, flow rate and viscosity) and hydrate

367

volume fraction versus time of the 0.75 wt.% wax content system (Exp.2) and the

368

wax-free system (Exp.1) are shown in Figure 7, wherein the pressure drop and flow

369

rate are recorded directly from the experiments while the fluid viscosity is calculated

370

inversely by Eq.(6). Note that Eq.(6) is only suitable for calculating the viscosity of

371

a system without hydrate deposition or a decrease in flow diameter. According to the

372

method presented by Majid et al.58 (further details on the method of Majid et al.58

373

are shown in Supporting Information part-B), the relative-pressure-drop trace of

374

Exp.1 as shown in Figure 8 closes to a value of approximately 1.00 before and after

375

hydrate formation, which means almost all the hydrate particles suspend in the

376

system without significant hydrate deposition (settling or bedding of hydrate

377

particles). In addition, no obvious deposit is observed by the high-pressure visual

378

window as shown in Figure 9, which verifies that hydrate deposition scarcely occurs

379

in Exp.1. Thus, Eq.(6) can be used for Exp.1. However, severe deposition occurs in 20


Page 20 of 53

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Energy & Fuels

380

Exp.2. Thus, it is not suitable when Eq.(6) is used to calculate the viscosity of Exp.2

381

after hydrate formation, shown as a dashed line in Figure 7a, which cannot approach

382

the true viscosity of fluid with the occurrence of deposition.

383

Figure 7a shows that the trends in the variation of pressure drop and flow rate in

384

Exp.2 are totally different from those of Exp.1. For Exp.1, flow properties remain

385

nearly stable until the time point of 1.85 h, before hydrates form. Three distinct

386

phases are observed after hydrate formation.

387

1.

The initial fast-growing and aggregation phase. From time points 1.85 h to

388

2.35 h, the pressure drop decreases while the flow rate decreases. The

389

calculated viscosity increases quickly, as the hydrate volume fraction

390

increases with a high rate of hydrate formation. The reasons for these

391

phenomena include: (i) the transition from a liquid-liquid dispersion to a

392

solid-liquid dispersion30,51; (ii) the collision and agglomeration of the hydrate

393

particles owing to the cohesive force30,59; and (iii) the collision of a hydrate

394

particle with another water droplet, leading to aggregation and so-called

395

sintering32.

396

2.

Dynamic recovery phase. From time points 2.35h to 3.85h, the hydrate

397

formation rate decreases owing to the limitation of mass transfer and heat

398

transfer27,60 and a weaker sintering effect. A fluctuating rise in flow rate and a

399

decrease in calculated viscosity are observed.

400 401

3.

Balanced phase. After time point 3.85 h, the flow rate, the pressure drop and the viscosity maintain a relatively stable state. A pseudo-single-phase fluid (as 21


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

402

a hydrate slurry) forms and flows under stable conditions5,61. No blockage

403

occurs because of (i) the dynamic recovery of flow shear stress and the

404

cohesive force; (ii) the function of AA that prevents further aggregation and

405

the appearance of larger aggregates; and (iii) the high flow rate of fluid that is

406

capable of holding hydrate aggregates as the dispersed phase within the

407

continuous phase.

408

It should be noted that the calculated viscosity during the hydrate formation

409

process in this flow loop without wax addition first increases to a high level and then

410

decreases to a stable state, variation of which has a good agreement with the

411

observations with rheometers30,51,62. The aggregates in the fluid may form because of

412

the cohesive force between hydrate particles or the sintering effect between hydrate

413

particles and water droplets. In addition, the cohesion and sintering effect is

414

supposed to induce the contact growth27. In the initial fast-growing and aggregation

415

phase, the number of water droplets is larger, resulting in a greater possibility of

416

sintering aggregation. In addition, the aggregates formed from the sintering effect

417

could hardly be broken by the flow shear stress32. As the number and size of the

418

aggregates increase, the effect of flow shear stress on the aggregates is strongly

419

enhanced. Then, the sintering effect fades out with a decreasing amount of

420

unconverted water droplets. The decrease in calculated viscosity can be mainly

421

ascribable to the weakening of hydrate growth, aggregation and sintering effect.

422

Finally, a balanced state is reached.

423

As for Exp.2, Figure 7a shows that the whole experimental process can be 22


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Energy & Fuels

424

divided into three phases by the time points 0.99 h and 1.98 h: before wax

425

precipitation, the wax precipitation phase and the hydrate formation and plugging

426

phase.

427

1.

428 429

Before wax precipitation, the changes in pressure drop and flow rate are not significant, similar to the wax-free system.

2.

Wax deposition phase. The onset of this phase is characterized by the

430

deflection point of the pressure-drop curve, as shown in Figure 7b. This is

431

because the precipitated wax crystals deposit on the wall resulting in a

432

decrease in the flow diameter. The amount of wax deposition on the wall

433

depends on the temperature difference between the inner pipe wall and the

434

fluid and wax content16,17. The wax deposition process in these flow

435

experiments is slow and continual, because of the low temperature difference

436

and low wax content.

437

3.

Hydrate-formation and plugging phase. The formation rate of Exp.2 is much

438

lower than that of Exp.1, which is supposed to be caused by the oil-water

439

interfacial adsorption of wax crystals that hinder the hydrate nucleation21,22

440

and growth process. Approximately 15 min after hydrate formation, a sudden

441

jump of pressure drop and flow rate occurs. Approximately 30 min after

442

hydrate formation, the pressure drop becomes relatively high and the flow

443

rate falls down to 700 kg·h-1. The final pressure drop of Exp.2 is

444

approximately 3.4 times greater than the value before hydrate formation,

445

although the final flow rate decreases nearly by half. This phenomenon is 23


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

446

explained by two main reasons as follows: (i) the reduction in flow diameter

447

caused by hydrate deposition; and (ii) the interaction among hydrate particles,

448

water droplets and wax crystals that produces high viscosity.

449

It should be emphasized that a 50% reduction in the initial flow rate means the

450

pipeline faces a high blockage risk. The flow loop will be totally blocked in a

451

short time after the flow rate lower than 700 kg·h-1 for all the tests in the

452

experimental conditions as listed in Table 3. Because the hydrate blockage

453

occurring in the flow loop is extremely hard to address, the time point at which

454

the flow rate decreases to 700 kg·h-1 is assumed to be a sign of a pipeline

455

plugging. Exp.2 with 0.75 wt.% wax content reaches a blocking state rather than

456

the balanced state compared to Exp.1 without wax addition, and the final hydrate

457

volume fraction (0.52 vol.%) for Exp.2 is fairly low compared with that for Exp.1

458

(Figure 7c). According to previous works13,34,61, the hydrate volume fraction

459

should be considerably higher to result in a blocking. Independent wax

460

precipitation and deposition of 0.75wt.% wax content without hydrate formation

461

or independent hydrate formation without wax addition could not produce this

462

high calculated viscosity or special rapid-plugging phenomenon. However, the

463

flow ability clearly will be reduced with the coexistence state of wax and hydrate

464

in the flow system.

24


Page 24 of 53

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Energy & Fuels

(a)

465 (b)

466 467 468 469

Figure 6. (a) Phase equilibrium calculation of hydrate formation. (b) System temperature and pressure versus time for Exp.2. Temperature of wax deposition onset is determined by the pressure-drop curve (see Figure 6b).

25


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

Page 26 of 53

(a)

470

(b)

(c)

471 472 473 474 475 476 477 478

Figure 7. (a) Pressure drop, flow rate, hydrate volume fraction and calculated viscosity versus time for Exp.1 (0 wt.% wax) and Exp.2 (0.75 wt.% wax). Text in black describes the phases of the experimental process of Exp.1, and text in red describes the phases of Exp.2. The dashed line indicates calculating method of viscosity for Exp.2 is not suitable. (b) Enlarged comparison of pressure drop for Exp.2 and Exp.1 before hydrate formation. The deflection point indicates the onset of wax deposition. (c) Enlarged image for the hydrate volume fraction of Exp.2.

26


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Energy & Fuels

479 480 481

Figure 8. Relative-pressure-drop58 traces as a function time for Exp.1 (0 wt.% wax) and Exp.2 (0.75 wt.% wax).

482

483

484 485 486 487

Figure 9. Images from the visual window at different hydrate formation time points for Exp.1: (a) before hydrate formation, (b) 30 min after hydrate formation, (c) 90 min after hydrate formation, (d) 150 min after hydrate formation, (e) 210 min after hydrate formation.

488

3.2. Characteristics of different plugging scenarios. As shown in Figure 10, 27


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

489

the variations in pressure drop, flow rate and hydrate volume fraction versus time

490

are plotted in one figure for each experiment including Exp.2, Exp.3 and Exp.4.

491

Results of the other flow experiments listed in Table 3 are presented in Figure S3 in

492

the Supporting Information. Since the key parameters of Exp.2-1 and Exp.3-1 show

493

fairly similar variation trends, the reproducibility of the flow experiments is verified.

494

Combining the analysis with Figure 7, there are three types of trends of the flow

495

properties after hydrate formation, which are possessed of the following

496

characteristics: (i) a sharp increase in pressure drop and a sharp decrease in flow rate

497

(Figure 10a), (ii) an initial increase and then a decrease in pressure drop with a

498

gradual decrease in flow rate (Figure 10b), and (iii) a gradual decrease in both the

499

pressure drop and flow rate (Figure 10c). Plugging will occur in all the flow

500

experiments in the presence of wax, while the time required for pipeline blockage to

501

occur after hydrate formation is different (see Table 4).

502

Figure 11 − Figure 13 illustrate the deposition process observed through the

503

high-pressure visual window of Exp.2, Exp.3 and Exp.4, respectively. It should be

504

noted that although different locations and types of deposition may occur, such as

505

initial growth at the top and bottom of the pipe and grow towards the middle or

506

growth on the overall surface of the wall, observations through the visual window

507

can provide useful qualitative information for deposition characteristics combined

508

with flow property data. The light source behind the visual window remains constant

509

during all experiments, so the degree of light penetration is used to qualitatively

510

analyze and estimate the amount of the complex deposition. A quantitative method 28


Page 28 of 53

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Energy & Fuels

511

to determine the amount of hydrate deposition requires further study. Figure 11

512

shows an obvious deposition process in Exp.2. Within 9 minutes after hydrate

513

formation (Figure 11b and Figure 11c), as the visual window is gradually coated

514

with deposits, the amount of light penetration through the visual window decreases

515

to its lowest level. After that, the deposition layer becomes thicker with little change

516

in light penetration (Figure 11d). Figure 13 shows that the coating deposits for

517

Exp.4 are fairly small compared with Exp.2, while Figure 12 shows that the

518

deposition state of Exp.3 is intermediate between Exp.2 and Exp.4. Three video

519

clips are also attached as the Supporting Information to give a better overall

520

observation. It should be emphasized that no obvious deposition on the visual

521

window is seen in Exp.1 where no wax exists (see Figure 9). Based on the visual

522

window observation, the deposition states of all the flow experiments are listed in

523

Table 4.

524

According to the trends of flow properties and visual window observations of the

525

flow experiments, three plugging scenarios are identified: (i) rapid plugging (Figure

526

10a and Figure 11, strong and severe), (ii) transition plugging (Figure 10b and

527

Figure 12, intermediate) and (iii) gradual plugging (Figure 10c and Figure 13,

528

weak). Table 4 tabulates the different plugging scenarios and their corresponding

529

features for all the experiments.

530

1.

For the rapid plugging, the severe deposition of aggregates sharply reduces

531

the flow diameter of the loop and results in a sharp increase in the pressure

532

drop. Since a large amount of hydrate deposits on the pipe wall, the overall 29


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

533

viscosity of the fluid may even decrease due to the lower concentration of

534

hydrate particles in the bulk flow, which requires further studies to verify.

535

(Calculated viscosity of this case far greater than the true viscosity.)

536

2.

For the gradual plugging, the gradual increase in viscosity owing to the

537

gradual aggregation reduces the flow rate and the pressure drop, but with

538

negligible deposition. (Calculated viscosity of this case close to the true

539

viscosity.)

540

3.

For the transition plugging, the amount of the complex deposition is in a

541

middle state between the rapid plugging case and the gradual plugging case,

542

and the final blockage results predominately from the increase of viscosity

543

rather than the wall deposition, which is similar to the gradual plugging case.

544

This judgement can be confirmed by Figure 14, which shows the calculated

545

viscosities by Eq.(6) of three plugging scenarios against hydrate volume

546

fraction. As seen, the calculated viscosity trace of transition plugging case in

547

Figure 14 is firstly close to that of the rapid plugging case, indicating the

548

occurrence of deposition, and then close to that of the gradual plugging case

549

until final blockage occurs, indicating that deposition presumably ceases and

550

the gradual increase of viscosity is the main cause of transition plugging.

551

A flow system with a lower water bath temperature and flow rate (e.g., Exp.2

552

and Exp.5) easily provokes rapid plugging, which occurs within 30 min after hydrate

553

formation. However, a longer time is required (> 75 min) for plugging after hydrate

554

formation for a flow system with higher water bath temperature and flow rate (e.g., 30


Page 30 of 53

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Energy & Fuels

555

Exp.4 and Exp.9), indicating a lower plugging risk. Detailed discussion combining

556

these two crucial parameters, water bath temperature and flow rate, is presented in

557

Subsection 3.4.

558

Another interesting phenomenon observed is that flow properties of the

559

gradual-deposition scenario (e.g., Exp.4 shown in Figure 10c) are similar to those of

560

the initial fast-growing and aggregation phase of the wax-free situation (i.e., Exp.1).

561

Although the wax-containing systems have the same AA dosage as the wax-free

562

system, blockage finally occurs in the waxy system, even with a much lower hydrate

563

volume

564

pseudo-single-phase hydrate slurry, so it is speculated that wax crystals hinder the

565

effect of AA molecules to some extent because of their adsorption at the oil-water

566

interface. No doubt that surfactants and pipe diameter will have a significant

567

influence on hydrate deposition and hydrate plugging mechanisms63. The present

568

work focuses on the effect of surfactants and wax on hydrate aggregation and

569

cohesive force. Studies with different types of surfactants, different wax contents

570

and different pipe sizes should be performed in the future, to investigate the effect of

571

wax on not only cohesive forces but also adhesive forces. The experiments

572

performed in this high-pressure flow loop are still meaningful for understanding the

573

effects of wax on plugging and for providing a reference for the fields.

fraction.

The

wax-free

system

with

AA

31


finally

becomes

a

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

(a) 1℃, 1400kg/h

574

(b) 3℃, 1400kg/h

575

32


Page 32 of 53

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Energy & Fuels

(c) 5℃, 1400kg/h

576 577 578

Figure 10. Pressure drop, flow rate and hydrate volume fraction versus time for (a) Exp.2, (b) Exp.3, (c) Exp.4.

579

580 581 582 583

Figure 11. Images from the visual window at different hydrate formation time points during Exp.2: (a) before hydrate formation, (b) 5 min after hydrate formation, (c) 9 min after hydrate formation, (d) 15 min after hydrate formation.

584

33


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

585 586 587 588

Figure 12. Images from the visual window at different hydrate formation time points during Exp.3: (a) 9 min after hydrate formation; (b) 15 min after hydrate formation; (c) 30 min after hydrate formation; (d) 45 min after hydrate formation.

589

590 591 592 593

594 595

Figure 13. Images from the visual window at different hydrate formation time points during Exp.4: (a) 15 min after hydrate formation; (b) 45 min after hydrate formation; (c) 75 min after hydrate formation; (d) 90 min after hydrate formation.

Figure 14. Calculated viscosity by Eq.(6) versus hydrate volume fraction for three 34


Page 34 of 53

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Energy & Fuels

596

597

plugging scenarios.

Table 4. Summary of different plugging scenarios and their corresponding features

Exp. No.

Exp.2 & 2-1, Exp.5,Exp.6, Exp.7 Exp.3 & 3-1, Exp.8 Exp.4, Exp.9

598

a, b ↑ and

Variation trend of flow property

Deposition state

Time required to plugging after hydrate formation (min)

Plugging scenarios

Pressure drop ↑ with flow rate ↓a

Severe

15~30

Rapid plugging

Intermediate

50~65

Weak

75~90

Pressure drop ↗&↘ with flow rate ↘b Pressure drop↘ with flow rate ↘

Transition plugging Gradual plugging

↓ represent rapid change, while ↗ and ↘ represent gradual change.

599

3.3. Evidence for the existence of wax-hydrate aggregates. In the previous

600

work36, hydrate/water masses with a hydrate volume fraction larger than 10% will

601

deposit on the pipe wall and result in the decrease of flow diameter. However, the

602

hydrate volume fractions are low for all the experiments with different plugging

603

scenarios (Table 4). Therefore, the function of wax should be considered to

604

understand the mechanism of the complex plugging in the system with wax addition.

605

Based on the in situ images of particles recorded by the PVM probe25,36,64 and the

606

estimation of the slurry viscosity, the coupling agglomeration of wax and hydrate is

607

supposed to exist.

608

As shown in Figure 15, the formation of wax-hydrate aggregates is observed.

609

Figure 15a and Figure 15b show the water droplets in the w/o emulsion in the flow

610

system36,45, providing interfaces on which AA molecules and wax crystals can be

611

adsorbed and hydrates can form. However, the obvious wax crystals of Exp.2 in 35


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

612

Figure 15b are not discerned, because of the small size of the precipitated wax

613

crystals. The weighted mean chord length of the precipitated wax crystals in the 0.75

614

wt.% wax content diesel oil measured by an offline FBRM probe ranges from 10 µm

615

to 15 µm. Akhfash et al.65 proposed that particles smaller than 20 µm presumably

616

could not be detected by the PVM probe. At 3 min after hydrate formation, evident

617

water droplets with hydrate shells (Figure 15c-A) are characterized by shiny

618

circles25, and wax-hydrate aggregates with special morphology are captured (Figure

619

15c-B). Figure 15d and Figure 15e illustrate the further agglomeration process and

620

the aggregates grow into a larger size, while this type of aggregates is not observed

621

in the wax-free condition (Figure 16) that is consistent with the observation in the

622

previous work36. Note that the existence of coupling aggregates does not mean that

623

the normal hydrate aggregates or the hydrate/water masses will not emerge, and

624

images in Figure 15 are typically selected to emphasize the existence of

625

wax-hydrate aggregates.

626

Another discussion about the hydrate slurry viscosity with wax addition using

627

the model developed by Camargo and Palermo31 can also give evidence for the

628

existence of wax-hydrate aggregates. Three crucial parameters dp, dA and f should be

629

specified before applying Eq.(3) − Eq.(5). The average size of the water droplets

630

(dp=40 ± 5 µm) and the maximum average size of the aggregates, as listed in Table

631

5, are determined by the statistics from the PVM probe, where the maximum

632

average size is defined by Eq.(9). The fractal dimension f is characterized by the

633

structure of the aggregates and the radial variation of the particle density inside the 36


Page 36 of 53

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Energy & Fuels

634

aggregates2. For the hydrate aggregates2, f is generally assumed to be 2.5. If the

635

effects of wax on the aggregation process and aggregate structure are neglected (f ≡

636

2.5), the size of aggregates will be the only varying parameter in this model.

Maximum d A =

637

k

5

i =1

j

∑∑ d

A,ij

5k

(9)

638

where k is the number of continuous PVM images used in the corresponding PVM

639

image sequence, 8 ≤ k ≤12; dA,i1 − dA,i5 are the size of the largest five aggregates in a

640

single PVM image.

641

Then, the comparison viscosities of the experimental fluid with wax and

642

hydrates estimated by Eq.(3) to Eq.(5) are listed in Table 5, where the comparison

643

viscosity of the flow system is defined as the ratio of the viscosity at a specific time

644

point or hydrate volume fraction to the viscosity at the onset of hydrate formation.

645

Table 5 shows that the viscosity estimated by Camargo and Palermo’s model is in

646

good accordance with the inversely calculated values using Eq.(6) for hydrate

647

slurries because both methods are suitable for describing a well-dispersed system

648

with low deposition level. However, there are some deviations for a system

649

containing wax. The largest deviation for Exp.2 is due to the severe deposition that

650

leads to the calculated viscosity by Eq.(6) largely deviating from the true viscosity.

651

Because the deposition state of Exp.4 and Exp.9 is supposed to be weak, the

652

influence of the flow diameter on the calculated viscosities by Eq.(6) can be ignored,

653

and calculated viscosities are thus much closer to the true viscosities. The original

654

viscosity model developed by Camargo and Palermo requires modifications for a 37


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

655

waxy w/o emulsion with hydrate particles, which suggests that the morphology and

656

the fractal structure of the aggregates in the presence of wax is totally different from

657

the normal hydrate aggregates. These above calculations also imply the existence of

658

special aggregation.

659

A conceptual diagram is presented to explain the formation mechanism of

660

wax-hydrate aggregate, as shown in Figure 17. It is hypothesized that fine wax

661

crystals in the flow system are adsorbed at the oil-water interface (Figure 17A and B)

662

because the emulsifier used is also a Span-series surfactant compared to our

663

previous work28. Haj-Shafiei et al.8 proposed that for a high water-cut w/o system

664

with 5% wax content, the amount of wax was insufficient to fully encase the

665

aqueous phase. Thus, for low wax content systems, the amount of wax is also

666

supposed to be insufficient to fully enwrap water droplets, which presumably is only

667

true for the case investigated in this work (0.75 wt.%) and requires further study.

668

After hydrates begin to form, the hydrate shell gradually forms on the surface of the

669

water droplets27,60 as shown in Figure 17C. The existence of wax crystals adsorbed

670

at the interface is supposed to increase the porosity66 of the hydrate shell, which is

671

similar to the impact of KHI67, and then results in large amounts of water permeation

672

(Figure 17D). Thus, the hydrate shell is easily coated by free water (Figure 17D)

673

and is much easier to be broken due to water permeation (Figure 17E). Afterwards,

674

the sintering effect and cohesive force between hydrate particles rise to a very large

675

scale, and wax-hydrate aggregates emerge (Figure 17F). This type of agglomerate is

676

hard to break by the flow shear. On the other hand, these adsorbed wax crystals will 38


Page 38 of 53

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Energy & Fuels

677

directly suppress the effect68 of AA molecules on the agglomeration of hydrate

678

particles, as mentioned in Subsection 3.2, because the compatibility between the

679

long alkyl ends of wax crystals at different water droplets is much higher. More

680

experiments should be done to inspect the yield strength of the aggregates and the

681

effects of wax crystals on the function of AAs. (a)

(b)

(c)

(d)

682

683 (e)

684 685 686 687

Figure 15. PVM images of Exp.2: (a) before wax precipitation, (b) after wax precipitation and before hydrate formation, (c) 3 min after hydrate formation, (d) 5 min after hydrate formation, (e) 9 min after hydrate formation. (Black circles are added to guide the eye.)

39


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

(a)

Page 40 of 53

(b)

688 689 690

Figure 16. PVM images of Exp.1: (a) 20 min after hydrate formation, (b) 60 min after hydrate formation

691

Table 5. Comparison viscosities obtained by inverse calculation and model estimation

692 693

Exp. No.

Deposition state

Hydrate volume fraction (%)

Exp.1 Exp.1 Exp.2 Exp.2 Exp.3 Exp.4 Exp.9

Weak Weak -Severe Intermediate Weak Weak

5.00 10.00 0.20 0.52 0.63 0.47 0.44

a

Maximum

200±20 200±20 550±50 550±50 450±50 350±50 310±50

d A (µm)

Comparison viscositya calculated by pressure drop (Eq.(6))

Comparison viscositya estimated by Camargo and Palermo’s model (Eqs.(3)-(5))

1.68 2.20 1.51 11.90 3.06 2.67 2.19

1.37~1.44 2.09~2.37 1.02 1.03~1.04 1.03~1.04 1.03~1.04 1.03~1.04

Comparison viscosity is defined as the ratio of the viscosity at a specific time point or hydrate

volume fraction to the viscosity at the onset of hydrate formation.

694

40


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Energy & Fuels

695

696

697

698 699

Figure 17. Conceptual diagram for the formation mechanism of wax-hydrate-aggregate

700

3.4. Mechanisms of different plugging scenarios. To understand the

701

mechanisms of different plugging scenarios, some analyses of wax deposits on the

702

walls should be studied first. Pressure drop is an effective parameter to determine

703

the deposit thickness for wax69. Based on a transformation of the Darcy-Weisbach 41


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

704

hydraulic friction formula, Eq.(10) can be obtained.

705

 D0     Dt 

5−m

Q  = 0   Qt 

2− m

Page 42 of 53

m

 µ0  ρ0 ∆Pt    µt  ρt ∆P0

(10)

706

where the subscript 0 refers to the time point when the system temperature reaches

707

WAT and wax start to precipitate, and the subscript t refers to the duration of wax

708

precipitation. Let µ0 = µm, where µm is the measured viscosity with temperature and

709

pressure modifications as shown in Eq.(1) for waxy w/o emulsion. Then, the average

710

thickness of wax-deposition layer δ can be determined by: D0-Dt=δ.

711

Based on Eq.(1) and Eq.(2), the pressure drop of Exp.9 before hydrate

712

formation is calculated by modified viscosities, as shown in Figure 18a. The

713

deviation between the experimental results and calculated values appears at time

714

point 1.14 h due to wax deposition that reduces the flow diameter. As wax continues

715

to deposit on the pipe wall, the deviation becomes larger, indicating the thickness of

716

the deposit layer becomes larger (see Figure 18b). Table 6 concludes the

717

wax-deposition duration, average wax-deposition thickness, hydrate formation

718

duration, average gas consumption rate and final hydrate volume fraction in several

719

flow experiments. Because the system temperature is lower with lower water bath

720

temperature (Exp.2 < Exp.3 < Exp.4) and lower flow rate (Exp.7 < Exp.3 < Exp.9)36,

721

the wax-deposition duration before hydrate formation will be shorter with lower

722

system temperature (Exp.2 < Exp.3 < Exp.4, Exp.7 < Exp.3 < Exp.9). We assume

723

that the total amount of wax precipitation at a certain temperature in the flow loop is

724

a definite value, which is the summation of deposits and bulk phase wax (suspension 42


Page 43 of 53 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

725

and adsorption). Then, for high-temperature and high-flow-rate systems (i.e., Exp.4

726

and Exp.9), there would be fewer wax crystals in the bulk phase when hydrates start

727

to form because the total amount of wax precipitation is lower due to a higher

728

system temperature and the amount of wax deposition is higher due to longer

729

deposition duration. After hydrate formation, the gas consumption rate is higher,

730

with a lower water bath temperature and lower flow rate, because of the higher

731

growth driving force (lower system temperature). Based on the formation

732

mechanism of wax-hydrate aggregates (see Figure 17), more wax crystals and

733

hydrates in the bulk phase would make it easier for the formation of larger

734

wax-hydrate aggregates. Based on the abovementioned discussion, the mechanisms

735

for the different plugging scenarios are presented as follows, and a conceptual

736

diagram is shown in Figure 19, where the values of the bulk-phase wax, deposit

737

wax and average gas consumption rate are qualitatively illustrated.

738

1.

For the low temperature system (Exp.2) and low flow rate system (Exp.7),

739

there were more wax crystals and hydrates in the bulk phase at every time

740

point during the initial fast-growing and aggregation phase, so a larger

741

amount of wax-hydrate aggregates emerged. Then, these large aggregates

742

resulted in a higher viscosity and a larger decrement in the flow rate, while

743

the lower flow rate conversely produced larger aggregates. At some time

744

point, the flow in the loop could not hold the large coupling aggregates any

745

more, leading to their deposition and the decrease in the flow diameter, which

746

resulted in an increase in the pressure drop and further decrease of the flow 43


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

747

rate. Finally, rapid plugging occurred due to the deposition of more

748

aggregates.

749

2.

As for high-temperature system (Exp.4) and high-flow-rate system (Exp.9),

750

fewer wax crystals and hydrates in the bulk phase produced smaller and

751

less-coupling aggregates. Although the viscosity increased as the hydrate

752

volume fraction increased, the pipe flow was still capable of holding these

753

smaller aggregates. Therefore, gradual plugging occurred due to a gradual

754

increase of viscosity.

755

3.

For moderate temperature and moderate flow-rate systems (Exp.3), the

756

amount of large-size coupling aggregates, which formed during the

757

fast-growing and aggregation phase, was not sufficient to produce a

758

stationary deposition layer. Thus, deposition of coupling aggregates occurred

759

in the first 30 minutes or so, then the pipe flow could hold the rest of

760

aggregates, corresponding to transition plugging.

761

For low-temperature systems and low-flow-rate systems, once hydrates began

762

to form, there was a catastrophic decrease in the transportation ability of the

763

pipeline, which meant an extremely high plugging risk. The temperature and flow

764

rate should be better controlled for systems with the coexistence of wax and

765

hydrate.

44


Page 44 of 53

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Energy & Fuels

(a)

(b)

766 767 768 769

Figure 18. (a) Pressure drop of Exp.9 calculated by modified viscosities before hydrate formation. (b) Deposition thickness of Exp.9 before hydrate formation. (Wax precipitates out at 1.14 h, and hydrate forms at 3.56 h.)

770 771

Table 6. Average deposition thickness before hydrate formation and final hydrate volume fraction of flow experiments Before hydrate formation After hydrate formation Final Wax Average Hydrate Average gas Set temperature hydrate Exp. deposition thickness of formation consumption (°C) / flow rate volume No. duration wax deposits duration rate a (kg·h-1) fraction (min) (mm) (min) (mol·min-1) (vol.%) 2 1/1400 45.6 0.16 27.0 0.074 0.52 3 3/1400 111.6 0.23 61.2 0.038 0.63 4 5/1400 232.8 0.20 97.8 0.017 0.47 7 3/1120 51.6 0.07 16.8 0.052 0.20 9 3/1640 135.4 0.28 84.0 0.019 0.44

772 773

a

Average gas consumption rate = total amount of gas consumption / hydrate formation duration (i.e.,

hydrate formation and plugging phase in Figure 7).

45


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

774 775 776

Figure 19. A conceptual diagram for different plugging scenarios affected by temperature and flow rate

777

4. CONCLUSIONS

778

The effect of wax on hydrate agglomeration behavior and plugging mechanisms was

779

studied by a high-pressure flow loop. For a wax-free system, a stable

780

pseudo-single-phase slurry finally formed due to the balance of agglomeration and

781

flow shear. For systems with wax addition, all the flow experiments finally went into

782

blockage with three plugging scenarios: rapid plugging, transition plugging and

783

gradual plugging, rather than the stable slurry flow. The formation of wax-hydrate

784

aggregates and the coupling deposition process were considered to be the

785

mechanism for rapid plugging, while a gradual increase in viscosity was the reason

786

for gradual plugging. The viscosity calculation also showed that wax-hydrate

787

aggregates had entirely different structures and morphologies than aggregates in

46


Page 46 of 53

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Energy & Fuels

788

wax-free systems. The combination of the average thickness of wax deposition and

789

gas consumption rates showed that systems with a lower temperature and a lower

790

flow rate were vulnerable to rapid plugging. Moreover, more attention should be

791

paid to the effect of wax on the efficiency of AAs. The findings of this work provide

792

a preliminary insight and investigation for the ongoing flow assurance in waxy

793

deep-water offshore fields.

794

SUPPORTING INFORMATION

795

Figure S1: The repeated DSC tests of diesel oil and diesel oil with 0.75 wt.% wax

796

content.

797

Figure S2: Relative-pressure-drop traces as a function time for Exp.1, constant

798

pumping at 20 vol.% water cut.

799

Figure S3: Pressure drop, flow rate and hydrate volume fraction versus time for

800

Exp.2-1, Exp.3-1, Exp.5, Exp.6, Exp.7, Exp.8 and Exp.9.

801

Three video clips: Observation of rapid plugging (Exp.2, normal playing speed),

802

transition plugging (Exp.3, 4 fold playing speed) and gradual plugging (Exp.4, 4

803

fold playing speed) through the visual window.

804

AUTHOR INFORMATION

805

Corresponding author

806

*

807

+86-10-89733804.

808

*

Bohui Shi, E-mail: [email protected]; Telephone: +86-10-89733804; Fax:

Jing Gong, E-mail: [email protected]; Telephone: +86-10-89733804; Fax: 47


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

Page 48 of 53

809

+86-10-89733804.

810

ORCID:

811

Yang Liu: 0000-0002-8556-8775

812

Bohui Shi: 0000-0003-2683-6984

813

Notes

814

The authors declare no competing financial interest.

815

ACKNOWLEDGEMENTS

816

This work was supported by the National Natural Science Foundation of China (No.

817

51534007),

818

2016YFC0303704), the National Natural Science Foundation of China (No.

819

51774303 and 51422406), the National Science and Technology Major Project of

820

China (No. 2016ZX05066005-001 and 2016ZX05028004-001), and the Science

821

Foundation of China University of Petroleum-Beijing (No. C201602), all of which

822

are gratefully acknowledged.

823

NOMENCLATURE

the

National

Key

Research

and

Development

Plan

µm

measured kinematic viscosity with modifications (Pa·s)

P

system pressure (bar)

A0

viscosity measured by the rheometer (ambient pressure, Pa·s)

Tt

system temperature (°C)

B0

exponent determined by pressure (bar-1)

µS

estimated dynamic viscosity of the suspension (Pa·s)

µL

dynamic viscosity of the continuous phase (Pa·s)

ψeff

effective hydrate volume fraction

ψmax

maximum hydrate volume fraction

dA

diameter of aggregates (m) 48


(No.

Page 49 of 53 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

dp

diameter of hydrate particles (m)

f

fractal dimension

γ&

shear rate (s-1)

Fa

cohesive force of hydrate particles (mN·m-1)

µc

calculated kinematic viscosity of the fluid (m2·s-1)

∆P

pressure drop of the flow loop (Pa)

D

flow diameter (m)

L

length of the flow loop (m)

g

gravitational acceleration (g=9.8 m·s-2)

β

factor determined by the flow regime of the fluid

m

exponent determined by the flow regime of the fluid

Q

flow rate (kg·s-1)

ρ

density of fluid (kg·m-3)

ng

mole number of gas consumption (mol)

P1

system pressure before hydrate formation (Pa)

P2

system pressure after hydrate formation (Pa)

Vg

gas volume in the separator (m3)

z1 and z2

compressibility factors in the pressure of P1 and P2

R

gas constant (J·mol-1·K-1)

T1

system temperature before hydrate formation (K)

T2

system temperature after hydrate formation (K)

φ

hydrate volume fraction

Mg

average molar mass of natural gas (kg·mol-1)

Nhyd

hydration number

Mw

molar mass of water (kg·mol-1)

ρH and ρw

density of hydrate and water (kg·m-3)

VL,i

initial volume of the liquid phase (m3)

δ

average thickness of wax deposition layer (m)

824

REFERENCES

825 826 827 828 829 830 831

(1)

Ngô, C.; Natowitz, J.B. Our energy future: resources, alternatives, and the environment. 2nd Ed. John Wiley & Sons, Inc, 2008.

(2)

Sinquin, A.; Palermo, T.; Peysson, Y. Rheological and flow properties of gas hydrate suspensions. Oil Gas

Sci Technol 2004, 59 (1), 41-57. (3)

Feng, J.C.; Wang, Y.; Li, X.S. Entropy generation analysis of hydrate dissociation by depressurization with horizontal well in different scales of hydrate reservoirs. Energy 2017, 125, 62-71.

(4)

Chong, Z.R.; Yang, S.H.B.; Babu, P.; Linga, P.; Li, X.S. Review of natural gas hydrates as an energy 49


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resource: Prospects and challenges. Appl Energ 2016, 162, 1633-1652. (5)

Sloan, E.D.; Koh, C.A.; Sum, A.K.; Ballard, A.L.; Creek, J.; Eaton, M.; et al. Natural gas hydrates in flow

assurance. Oxford: Gulf Professional Publishing, 2010. (6)

Gao, S.Q. Investigation of Interactions between Gas Hydrates and Several Other Flow Assurance Elements.

Energ Fuel 2008, 22 (5), 3150-3153. (7)

Koh, C.A.; Sloan, E.D. Clathrate hydrates of natural gases. 3rd Ed. New York: CRC Press, 2008.

(8)

Haj-Shafiei, S.; Ghosh, S.; Rousseau, D. Kinetic stability and rheology of wax-stabilized water-in-oil emulsions at different water cuts. J Colloid Interf Sci 2013, 410, 11-20.

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