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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
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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
42
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
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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
55
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
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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,
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the deposits on the cell wall were probably a mixture of wax and hydrate particles.
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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
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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
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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.
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Otherwise, the collision of a hydrate particle with another water droplet was
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observed by Aman et al.32 using a micromechanical force (MMF) apparatus, called
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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
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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
103
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
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than the flow shear stress37. Therefore, the flow rate is a critical parameter to affect
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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
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finally
becomes
a
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(a) 1℃, 1400kg/h
574
(b) 3℃, 1400kg/h
575
32
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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
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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
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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
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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
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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
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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
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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
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(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
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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
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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
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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
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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
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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
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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
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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
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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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