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Hydrate deposition on cold pipe walls in W/O emulsion systems Lin Ding, Bohui Shi, Jiaqi Wang, Yang Liu, Xiao-fang Lv, Haihao Wu, Wei Wang, Xia Lou, and Jing Gong Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00559 • Publication Date (Web): 04 Aug 2017 Downloaded from http://pubs.acs.org on August 16, 2017

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Hydrate deposition on cold pipe walls in W/O emulsion systems Lin Dinga, Bohui Shia*, Jiaqi Wanga, Yang Liua, Xiaofang Lva,b, Haihao Wua, Wei Wanga, Xia Louc, Jing Gonga* a

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

Engineering /Beijing Key Laboratory of Urban Oil and Gas Distribution Technology, China University of Petroleum-Beijing, Beijing 102249, People’ s Republic of China b

Jiangsu Key Laboratory of Oil and Gas Storage and Transportation Technology, Changzhou University, Changzhou, Jiangsu 213016, People’s Republic of China

c

Department of Chemical Engineering, Curtin University, Kent Street Bentley, WA 6102, Australia Corresponding author’s e-mail: [email protected]

Abstract: Hydrate deposition is a major concern in the oil and gas industry. This paper studied the hydrate deposition mechanisms in W/O emulsion systems using a high-pressure flow loop. The experimental results indicated that the hydrate deposition process can be divided into four stages: the initial formation and deposition, deposit sloughing, secondary formation and redeposition, and deposit annealing. For the first time, a method to quantify hydrate deposits was proposed. The results showed that a low temperature, high pressure, high additive concentration and low water cut decreased the amount of hydrate deposits. The hydrate deposition amount first increased and then decreased with an increasing flow rate. The experimental results demonstrated that the hydrate deposition process is affected by the hydrate formation driving force, wall surface properties, adhesive water amount, mass transfer coefficient and flow shear force.

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Key words: gas hydrates; deposit amount; emulsion system; quantitative method; influence factors.

1. Introduction Gas hydrates are complex crystalline compounds that are formed by gas and water molecules under high-pressure and low-temperature conditions.1 In recent years, as the petroleum industry has moved into deeper waters, gas hydrates have become a major hazard in undersea gas/oil exploitation and transportation systems.2 Traditional methods for hydrate prevention, including pipeline insulation, pressure reduction and thermodynamic inhibitor injection, have been used for decades in field productions. However, the high economic costs associated with these methods have made them less acceptable for future field productions with a high water cut.3 An alternative method to control hydrates is the hydrate risk management strategy, which allows hydrates to form but prevents their agglomeration. In this method, the petroleum fluid is transported as a slurry, and the hydrate particles can agglomerate in the bulk liquid and deposit on pipe wall surfaces. The hydrate deposition can decrease the flow section area and increase the pressure drop and potentially result in the formation of a hydrate plug in the flow line. However, only a few investigations on hydrate deposition are available in the open literature, and the hydrate deposition mechanism is not well understood. A study from the Southwest Research Institute showed that hydrates form in the 2


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bulk liquid and on the pipe wall surfaces,4 and this finding is important for understanding the hydrate deposition phenomenon. Lingelem et al.5 noted that the factors affecting the hydrate deposition process include the degree of supercooling, wall heat flux, internal cooling, flow rate, and fluid properties and emulsification of the liquid phases. However, they did not report how these factors influence the hydrate deposition process. In addition, they noted that the hydrate layer could act as an insulating layer and that the insulating property depended on the thickness of the layer. Nicholas et al.6 studied the adhesive forces between cyclopentane (CyC5) hydrates and carbon steel. Their results indicated that these forces were weaker than those between the CyC5 hydrate particles. They also reported that hydrate particle deposition did not occur at a typical operating flow rate in offshore oil and gas pipelines when no free water was available and the hydrate particles were larger than 3 microns. This was due to the strong flow shear force that prevented the hydrate particles from adhering to the pipe wall surface. Aspenes et al.7, 8 studied the effect of the material and crude oil compositions on the wettability of pipeline-like surfaces and the subsequent effects on hydrate deposition on the pipe wall surface. Their results showed that the surfaces with the lowest surface free energy had the lowest adhesion energy between water and the solid surface in crude oil. Additionally, they found that the same oil components 3


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influenced both the hydrate crystal surface and the pipeline surface, and an oil composition with a high acid content was the most effective for preventing plug formation. Nicholas et al. proposed two different hydrate deposition mechanisms based on their experimental study, which was conducted in a water-saturated liquid condensate system using a single-pass flow loop.9 They found that if the experimental temperature was above the liquid-water saturation curve, a lengthwise uniform deposit would form, and a gradual pressure drop in the flow loop would increase. However, if the temperature was below the liquid-water saturation curve, a localized hydrate restriction and a rapid pressure drop increase would occur due to free water coalescence. Then, Nicholas et al. established a model to predict hydrate deposition using the mass and energy balance.10 The model results indicated that a hydrate deposit layer would anneal with time, and this is similar to the phenomenon observed in both frost and wax deposition processes.11-13 Balakin et al. studied the hydrate formation and deposition processes using a multiphase flow loop and established a computational fluid dynamics (CFD) numerical model based on the experimental data.14 The proposed model reproduced the experimentally observed bed formation process. They found that the thickness of the simulated hydrate bed and the vertical hydrate concentration gradient in the bed were sensitive to the mean flow velocity, hydrate particle size and solid stress model

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used in the simulation. Rao et al. conducted a series of experiments to study hydrate formation and deposition on a cold surface in water-saturated gas systems.15 According to their experimental results, they divided the hydrate deposition process into three stages: initial formation, growth and hardening. The hydrate deposit was observed to change from a porous deposit to a non-porous deposit. Additionally, they found a limit to the deposit thickness, which increased with the increasing degree of subcooling. Grasso et al. conducted an experimental study on the hydrate deposition in both a rocking cell and a lab-scale flow loop.16 The experiments in a rocking cell demonstrated that the hydrate deposition process was mainly affected by two factors: the temperature gradient between the liquid bulk and the pipe wall and the liquid flow rate. Three hydrate deposition mechanisms were found in the rocking cell experiments: film growth, a combination between film growth and hydrate particle migration and hydrate bedding. The dominant mechanism is determined by the temperature gradient between the bulk and the pipe wall as well as the fluid system. Finally, the flow loop experiments revealed that the hydrate deposits mainly formed via three mechanisms: water diffusing through the medium (mineral oil or gas), water wetting the deposition surface (water entrainment in the gas phase or free water layer) and hydrate particles adhering to a hydrate layer or metal surface. Vijayamohan et al. proposed a mechanism for the hydrate deposition process in 5


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partially dispersed systems.17-18 They noted that the oil phase carries some of the water phase to the top wall of the pipe, wetting the pipe wall surface. Then, when the hydrates begin to form, they form a hydrate film/deposit on the pipe wall surface because of the wetting of the pipe walls. They also found that the formed hydrates occlude some water to form large hydrate/water masses, which could eventually lead to hydrate bedding and deposition. The studies mentioned above uncovered some key issues in the hydrate deposition process: 1) the factors that affect the hydrate deposition process, 2) the influence of different oil compositions on hydrate deposition, 3) the mechanisms of the hydrate deposition process, and 4) the stages of the hydrate deposition process in water-saturated gas systems. This present work investigated hydrate deposition mechanisms in W/O emulsion systems using a high-pressure flow loop. Hydrate deposition in W/O emulsion systems is different than that in water-saturated gas systems. Hydrate deposition in water-saturated gas systems occurs mainly via the film growth mechanism, which was studied by Nicholas et al.9 and Rao et al.15 This film grow process is very slow and mainly occurs on the hydrate/gas interface. While in W/O emulsion systems, the hydrate particles can be suspended in the liquid bulk and move with the liquid flow, and they may adhere on the pipe wall surface during the slurry flow process. This is similar to the mechanism proposed by Grasso et al.16 and Vijayamohan et al.17-18 Currently, quantifying hydrate deposits and the effect of the

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operating pressure, flow rate, and water cut on the hydrate deposit volume is challenging. In this work, the hydrate deposition process was directly recorded using a video camera mounted on the test section. A method was established to quantify the hydrate deposits. Then, the influences of the experimental temperature, pressure, antiagglomerant inhibitor (AA) concentration, water cut and flow rate on the hydrate deposit amount were investigated.

2. Experimental Section 2.1. High-pressure flow loop A high-pressure flow loop, shown in Figure 1, was used for all the experimental work. The loop was 30 m long with an inner diameter of 2.54 cm. The design pressure was 15 MPa, and the operational temperature range was from -20°C to 100°C. The pressure was controlled by injecting natural gas into the separator, and the temperature was controlled using four Julabo glycol baths. The flow loop was equipped with 8 temperature sensors and 5 pressure transducers to monitor the temperature and pressure changes. The pressure transducers were from Endress Hauser D7012A0109C and had a precision of 0.01 kPa. The temperature sensors were thermocouples with a precision of 0.01°C and were made in China by Kunlun (model number KAWP-241). Two flow meters were equipped to monitor the gas flow rate and liquid flow rate, respectively. A density meter (Endress Hauser D50DA702000) with a precision of 0.01 g/cc was equipped on 7


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the test section to capture the fluid density data, which was a key parameter used in this work to quantify the hydrate deposits. A real-time particle analysis was performed using a focused beam reflectance measurement (FBRM) probe and a particle video measurement (PVM) probe, which were equipped on the liquid entrance section to monitor the hydrate particle chord length and the particle/agglomerate morphology, respectively. In addition, the flow loop had four sight windows to allow for direct visual observation of the hydrate deposition process. The sight windows were composed of a synthetic, high-pressure resin that can withstand pressures up to 10 MPa. The window thickness was 2 cm, and the transparency was approximately 93%. The manufacturer of this sight window was the Jianfeng Material Limited Company from Guangzhou, China. 2.2. Materials and procedure The materials used in this work include civil natural gas, deionized water, -10# diesel and the AA. The compositions of the civil natural gas and -10# diesel oil are shown in Table 1 and Table 2, respectively. At atmospheric pressure and 20°C, the density of the -10# diesel is 803 kg/m3, and its viscosity is 6.76 cP. The AA used in this work was kindly provided by the Chemical Engineering Department of the China University of Petroleum, Beijing. The AA was a non-ionic-type AA extracted from a saponin plant.19 The performance of this AA has been studied by several researchers, and it has been shown to improve the dispersity of both water droplets and hydrate

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particles. 20-22 The emulsification abilities of the materials used in this study were examined using a PVM probe to ensure that the systems were W/O emulsions. The PVM images are shown in Figure 2 for the emulsion without AA and Figure 3 for the emulsion with 1% AA. Because the water droplets in the PVM images show six light spots, the water droplets in the PVM images were easily recognized. Figure 2 clearly shows the water droplets suspended in the liquid bulk under the 10%-30% water cut conditions, which indicated that the W/O emulsion forms under these water cut conditions. However, for the 40% water cut condition, no water droplets can be seen in the PVM image, which indicated that an O/W emulsion forms under this water cut condition. Figure 3 shows the conditions with 1% AA. Even though the image appears to be milk white and distinguishing between the water droplets and gas bubbles is difficult because some AA molecules can adsorb on the droplet surface, the six light spots from some of the water droplets are still observed. Therefore, the system remains a W/O emulsion after the addition of the AA. The operating parameters for each experiment are listed in Table 3. We performed several repeat experiments for each of the experimental conditions, and the results were repeatable. The experimental procedure was as follows: 1) Before each experiment, we cleaned the flow loop to remove any residual AA. First, we discharged the loaded oil and water and used fresh water and oil to rinse 9


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the flow loop for the first time. This process cleaned most of the residual AA because the AA can dissolve in the W/O mixture. Then, we rinsed the flow loop several times using fresh water and a detergent, and this was followed by rinsing the flow loop with tap water several times until the discharged water was clean. Next, an air purge was used to remove any residual water, and finally, the loop was subjected to a vacuum of -1 bar to remove any air. 2) After this preparation, deionized water and diesel (and the AA, if needed) were loaded into the separator. The total volume of the liquid was 50 L, and the water cut was defined as the ratio of the water volume to the total liquid volume. 3) Then, natural gas was injected into the separator to reach a set pressure (5 MPa to 8 MPa in this work). There was no gas supply during each experiment. All the experiments were conducted with a constant initial pressure. 4) After this, the liquid fluid was circulated in the loop to form a stable W/O emulsion. During this period, the liquid density and water droplet chord length distribution were recorded by the density meter and the FBRM probe, respectively. The FBRM probe used in our work is a Mettler Toledo FBRMD600 model.23 5) Once the readings of the above parameters were stable, the system was cooled by setting the water bath temperature to a constant value (-3°C to 5°C in this work). During this cooling process, the hydrates formed, and the experimental data, 10


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including the pressure, temperature, flow rate, liquid density, video images and particle chord length, were recorded. The hydrate formation and growth were assumed to be complete when all the parameters were constant. The water bath was set to 30°C for 30 h to decompose the hydrates prior to beginning another experiment.

3. Deposition Phenomenon and Quantitative Method 3.1. Hydrate deposition phenomenon The typical results of a hydrate deposition experiment are shown in Figure 4. For the convenience of the discussion, the whole process was divided into five sections labeled using the letters A-E. As shown in Figure 4(a), as the temperature decreased (black line), the hydrates began to form at point A, and the hydrate onset temperature of approximately 9.3°C was defined as the hydrate critical crystallization temperature in this experiment. Then, from point A to point B, the temperature first increased due to the hydrate formation and then decreased. During this period, the liquid flow rate gradually decreased, as shown by the red line. This was due to the viscosity increasing as a result of the hydrate formation and the decreasing temperature. At the same time, the liquid density also decreased (blue line). Notably, the liquid density did not change substantially when the liquid temperature decreased from 21°C to 9.3°C prior to the hydrate formation, which indicated that the temperature variation had little effect on 11


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the liquid density. Therefore, in stages A to E, the influence of the temperature decrease on the liquid density was negligible. Therefore, further investigation was required to determine the reason for the decrease in the density. Hydrate formation can lead to a decrease in the density because natural gas hydrates have a lower density than water. Therefore, the decrease in the density might be caused by the hydrate formation. We can calculate the hydrate slurry density as follows: The gas consumption is calculated using the pressure difference before and after each experiment: ng =

P1V PV − 2 zRT1 zRT2

(1)

where ng is the number of moles of gas consumed (mol), P1 is the pressure before the hydrate formation (Pa), P2 is the pressure after the complete hydrate formation (Pa), V

is the gas volume in the separator (m3), z is the compressibility factor in the

experimental pressure, R is the gas constant (J/mol/K), T1 is the temperature before the hydrate formation (K), and T2 is temperature after the hydrate formation was complete (K). Using ng , the volume of the formed gas hydrates can be calculated by

VH =

ng M g + Nng M w

ρH

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(2)

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Where VH is the hydrate volume (m3), M g is the molar mass of natural gas (g/mol),

N

is the hydration number, M w is the molar mass of water (g/mol), and ρ H is the hydrate density (kg/m3). The volume of the unconverted water can be calculated by:

Vw' = Vw −

Nng M w

(3)

ρw

where Vw' is the volume of the unconverted water (m3) and Vw is the total volume of the water added into the loop (m3). Then, the slurry density was calculated by

ρs =

ms ρ HVH + ρ wVw' + ρoVo = Vs VH + Vw' + Vo

(4)

where ρ s is the density of the slurry in the pipeline (kg/m3), ms is the mass of the slurry (kg), Vs is the total volume of the slurry (m3), ρo is the density of the diesel oil (kg/m3), and Vo is the volume of the oil (m3). However, the calculated density-time profile did not agree with the measured density-time profile, as shown in Figure 4(b). The magnitude of the reduction in the measured density was much larger than that of the calculated density. Therefore, the decrease in the density was not caused by the hydrate formation. However, the decrease could be a consequence of hydrate deposition on the wall of the pipeline. The hydrates (with occluded water) are heavier than

diesel

oil

(with

a

density

of

approximately

803

kg/m3

at

standard atmospheric pressure and 20°C). Therefore, the deposition of the hydrates

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can cause a significant reduction in the mixed density of the liquid bulk. In addition, the hydrate deposition was also evidenced by the video images recorded through the sight window, as shown in Figure 5. During the experiment, a thick hydrate deposition layer was observed on the pipe wall surface. From B to C in Figure 4(a), the flow rate and liquid density continued to decrease, which indicated that the hydrate deposition process continued. During this time period (approximately 3 h), the liquid temperature increased from 6.5°C to 8.0°C (the set temperature of the glycol bath was constant at 5°C). This demonstrated that the hydrate deposition layer had a good thermal insulation function. At point C, a rapid increase in the slurry density was observed. This was accompanied by a rapid decrease in the flow rate. The image taken at the same stage showed a gradual sloughing of the hydrate deposition layer (Figure 5(e)). This can be seen by comparing the deposition layer in Figure 5(e) with the layer in Figure 5(d). The thinning of the layer is apparent. As shown in Figure 4(b), the counts of particles larger than 100 microns also rapidly increased during this period due to the sloughing of the hydrates. The sloughing process may also result in the release of unconverted water, which was occluded in the deposit layer. This would lead to a secondary hydrate formation in the liquid bulk. Due to the secondary hydrate formation, the temperature further increased from 8.0°C to 9.3°C from point C to point D and reached the critical 14


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crystallization temperature. Hydrates ceased to form at this temperature. Then, from the layer sloughing to point D, the slurry density rapidly decreased again, indicating that hydrate redeposition may have occurred. Unfortunately, the redeposition process could not be captured by the video camera due to the small deposition volume and because the deposition may have occurred at other locations in the flow loop. This redeposition process has not been confirmed, and the process is only inferred based on the slurry density variation data. From point D to E, the temperature was constant at the critical crystallization temperature (approximately 9.3°C), and the net changes in the liquid density and flow rate were relatively low. During this period, the net deposition was significantly reduced. Then, as seen in Figure 5(f), the hydrate deposit layer appeared to gradually become more compact, which is very different from the creamy-looking deposit layer shown in Figure 5(d). This phenomenon may be similar to the annealing process that was proposed by Rao15 in water-saturated gas systems. From point E onwards, the system stayed was stable, and the flow parameters no longer changed. The above results indicated that the hydrate deposition process can be characterized by the slurry density change and can be divided into four steps as follows: (1) Growth: after the hydrate formation begins, the hydrates begin to deposit and grow on the pipe wall. During this period, the hydrate deposition layer gradually 15


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thickens. (2) Sloughing: as the hydrate layer thickens to a certain thickness, it begins to slough. This sloughing process is likely caused by the continuous flow shear, the increasing amount of hydrate deposits and the increasing temperature of the deposit surface. (3) Re-deposition: the hydrate sloughing process can release some occluded water from the hydrate deposit layer, and this causes a secondary hydrate formation in the liquid bulk, leading to the redeposition of the hydrate particles. This process was inferred from the slurry density variation and was not evidenced by visual observations. (4) Annealing: in this stage, the hydrate deposition layer appears to gradually become more compact. This stage was observed in the video images and could not be identified from the experimental data. This stage is only suggested. 3.2. Quantitative method to determine the hydrate deposition amount As discussed above, the changes in the slurry density can reflect the hydrate deposition process. The slurry density decreases when the hydrates deposit, and the slurry density increases when the hydrates slough off the pipe. In this section, a new method is proposed to estimate the amount of the hydrate deposit based on the variations in the slurry density.

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First, the volume of the formed hydrates and the volume of the unconverted water were obtained using Equation (2) and Equation (3), respectively. According to Lv et al.’s study, the hydrates growth process in W/O systems can be divided into four stages, as shown in Figure 6.24 The authors demonstrated that in the last hydrate growth stage, all the unconverted water is occluded in hydrate agglomerates, and no free water exists in the oil phase. In this work, the PVM images for the final stage of the experiments also show that little to no free water droplets existed in the liquid phase, as shown in Figure 7. The PVM images only sample a small fraction of the entire system. However, to calculate the hydrate deposit amount, we made an assumption that the unconverted water was all occluded in the hydrate agglomerates when the hydrate growth was complete. Therefore, we considered the unconverted water and the hydrates as one unit, namely, hydrate/water masses, and the density can be calculated by

ρ H −W =

M H −W ρ wVw' + ρ H VH = V H −W Vw' + VH

(5)

where VH −W is the volume of the hydrate/water masses and M H −W is the mass of the hydrate/water masses. A portion of the hydrate/water masses deposits on the pipe wall surface, resulting in a reduction in the slurry density, and the rest of the hydrate/water masses remain suspended in the liquid bulk. Assuming the volume of the suspended hydrate/water

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' masses, VH −W , Equation (6) can be used:

ρ s = ρ mea =

ms ρ H −W VH' −W + ρoVo = Vs VH' −W + Vo

(6)

where ρ mea is the measured density of the slurry (kg/m3) that was recorded by the density meter. Then, the deposition ratio, r, which is defined as the volume percentage of the hydrate/water masses deposited against the total volume of the hydrate/water masses, can be calculated by

r=

VH −W − VH' −W VH −W

(7)

4. Results and Discussion Based on the proposed quantitative method and the experimental data, the influences of the different operating parameters, including the temperature, pressure, AA dosage, water cut and flow rate, are discussed in this section. 4.1. Influence of the experimental temperature and pressure Temperature and pressure are two important parameters in the hydrate formation process because they represent the hydrate formation driving force. In this work, the equilibrium temperature of the natural gas used was calculated using the HyFlow software, which was programmed by the China University of Petroleum, Beijing. The in-built model for the hydrate equilibrium calculation is the Chen-Guo model. The 18


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phase equilibrium curve for the natural gas is shown in Figure 8. The variations in the deposition ratios at different experimental temperatures are shown in Figure 9. The error bars in the figure represent the standard deviation from the average deposition ratio. The experiments were performed under 6 MPa pressure with 1% AA and a 30% water cut. The equilibrium temperature under this pressure was 11.45°C. Therefore, as the experimental temperature increased from -3°C to 5°C, the supercooling degree decreased from 14.45°C to 6.45°C. This operating temperature was the temperature of the coolant, and the temperature of the liquid bulk was much higher than that temperature. Therefore, no ice formed during the experiments. Figure 9 shows that as the temperature increased, the deposition ratio increased from 55% to 92%. Even the minimum deposition ratio was larger than 50%, which indicated that under these specific experimental conditions, most of the hydrate/water masses deposit on the pipe wall surface instead of being suspended in the liquid bulk. This also indicated that the hydrate deposition was not negligible in the hydrate formation and slurry flow processes, which was also noted by Vijayamohan17-18 and Majid24. By assuming that the deposited hydrates uniformly distribute on the pipe wall surface, the hydrate deposit thickness can be estimated from the hydrate deposition ratios. The results in Figure 9 show that as the deposition ratio increased, the deposit thickness increased from 3.75 mm to 6.25 mm, which indicated that the maximum value of the deposit thickness may reach up to half that of

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the pipe radius (12.7 mm). The variations in the hydrate deposition ratios and the deposit thicknesses under different operating pressures are shown in Figure 10. The experiments were conducted at 0°C with 1% AA and a 20% water cut, and the equilibrium pressure at this temperature is 1.46 MPa. As the experimental pressure increased from 5 MPa to 8 MPa, the deposition ratio decreased from 39% to 16%, and the deposit thickness decreased from 1.74 mm to 0.76 mm. This indicated that a higher pressure can weaken the hydrate deposition process and reduce the hydrate deposition amount. According to the above results, the hydrate deposition process is less severe at lower temperatures and higher pressures. Lower temperatures and higher pressures result in a higher driving force for the hydrate formation process, and the hydrate deposition process is less severe under a higher driving force. As Vijayamohan et al. proposed in their study, in the initial stage of the hydrate formation process, hydrates and water form hydrate/water masses in the liquid bulk through occlusion and collision.17-18 In the study of Lv et al., they also observed hydrate/water masses during the hydrate/water rearrangement stage.23 We believe that the formation of the hydrate/water masses may play an important role in the hydrate deposition process, and Aman et al.’s study showed that the water phase obviously strengthened the adhesion force between the hydrates and the solid surface.25-27 In our experiments, we also observed hydrate/water masses in the PVM images, which are shown in Figure

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11. Before the hydrate formation onset (Figure 11-a), water droplets were suspended in the oil phase. Then, (Figure 11-b) the hydrates begin to form on the water droplets as a hydrate shell. In this stage, only some of the water droplets are coated by the hydrate shell, and others remain as unreacted water droplets. As the hydrates and water droplets move with the liquid flow, they contact and collide with each other to form large hydrate/water masses, as shown in Figure 11-c. Then, the hydrates continuously form and grow as both hydrate/water masses and individual hydrate particles, as shown in Figure 11 d-e. In this process, the water on the surfaces of the hydrate/water masses will gradually transform into hydrates, and the water inside the hydrate/water masses will be occluded in the masses. Additionally, most of the individual water droplets will be consumed (or coated by hydrates) during this process, and we can see in Figure 11-f that in the final stage of the experiment, no water droplets were observed in the liquid phase. From the above process, we can infer that there are potentially three water phases during the hydrate formation and growth process. The phases are the unreacted individual water droplets, the water occluded in the hydrates and the water on the surfaces of the hydrate/water masses. Therefore, the unreacted individual water droplets and the surface water may have important roles in the hydrate deposition process because they can act as the adhesive water (or the water bridge) between the hydrates and the deposit layer. As the hydrate particles or hydrate/water masses move with the liquid flow, they may adhere on the pipe wall surface due to the effect of the adhesive water and form a hydrate deposit. 21


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During this process, if the adhesive water is depleted (i.e., turns into hydrate or is coated by the hydrate shell), the deposition process can slow or even cease. Therefore, the amount of the adhesive water can be a key factor in the hydrate deposition process. For a system with a higher driving force, the consumption of the adhesive water will be faster, which means that a higher driving force can shorten the action time of the adhesive water. For low driving force conditions, in contrast, the consumption rate of the adhesive water will be reduced, which prolongs the action time of the adhesive water. Therefore, the hydrate deposition amount is larger under low driving force conditions. This is likely why the higher driving force can reduce the hydrate deposition ratios. 4.2. Influence of AA dosages on the hydrate deposition The addition of AA is an important method in the hydrate risk management strategy. AA can reduce the agglomeration degree of hydrate particles and lower the risk of plugging due to hydrates. In this section, three AA concentrations were tested: 0%, 1% and 3%. The results are shown in Figure 12. Figure 12 shows that for each of the water cut conditions, the hydrate deposition ratio decreases with the increasing AA concentration. In addition, the hydrate deposit thickness also decreases as the AA concentration increases. This indicates that increasing the AA concentration can help reduce the amount of hydrate deposition. As we mentioned in part 4.1, hydrates may agglomerate and then adhere on the pipe wall 22


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surface due to the influence of adhesive water. Therefore, the AA may affect the hydrate deposition process in two ways. First, the AA molecules may hinder the adhesion process between the hydrates and the pipe wall surface by adsorbing on the pipe wall surface. Researchers have suggested that the water-wet pipe wall surface is a critical site for hydrate formation and deposition.26-32 Esmail et al.’s results indicated that the water phase extended on the carbon steel material, which could cause hydrate propagation.31 However, according to Esmail et al.’s study, the water extension and hydrate propagation were less obvious on a solid with a lower surface free energy, and they did not occur if the solid surface’s free energy was lower than 39 mJ/m2. Aman et al.27-28 studied the adhesion force between the hydrates and chemically modified surfaces. Their study indicated that the AA could lower the hydrate adhesion force and suppress both the hydrate deposition and particle agglomeration. Aspenes et al.7-8 conducted a systematic study on the wettability of petroleum pipeline materials and the subsequent effect on the hydrate deposition. Their results indicated that materials with a high wettability (low contact angle) have a higher risk of hydrate deposition and hydrate plugging. In addition, they suggested that the AA can adsorb on the hydrate surface and the pipeline surface, creating oil-wet surfaces. Thus, they concluded that the AA can reduce the risk of hydrate deposition and plugging. According to the above studies, the hydrate formation and deposition are highly dependent on the solid

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surface’s free energy. Therefore, since the AA can adsorb on the pipe wall surface and reduce the surface’s free energy, it can also reduce the hydrate deposition amount. Second, the AA can also improve the hydrate particles’ dispersity and allow them to remain dispersed in the liquid phase. Figure 13 shows the hydrate particles’ chord length distributions for different water cuts and AA concentrations, and the AA improves the dispersity of the hydrate particles. In addition, the performance of the AA can be obtained by comparing the PVM images in Figure 2 and Figure 3. In Figure 3, the water droplets are much smaller than those in Figure 2. 4.3. Influence of the water cut on the hydrate deposition Figure 14 shows the variations in the deposition ratios for different water contents with 1% AA at two different flow rates. Four water cuts are included: 10%, 15%, 20% and 30%. As the water cut increases from 10% to 30%, the deposition ratio increases from 0% to 27% for the lower flow rate and 0% to 68% for the higher flow rate. Additionally, the deposit thickness increases from 0 mm to 1.74 mm for the lower flow rate and 0 mm to 4.57 mm for the higher flow rate. This indicates that for the W/O emulsion systems, the hydrate deposition is more serious under the higher water cut conditions. This is because in high water cut systems, the total hydrate amount is larger because the systems have more water that can be used to form hydrates. Additionally, the amount of adhesive water is also larger in the high water cut systems, leading to a larger hydrate deposition ratio. Because both the hydrate and 24


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adhesive water amounts are larger in high water cut systems, the hydrate deposition amount significantly increases as the water cut increases. 4.4. Influence of flow rate on the hydrate deposition In part 4.3, Figure 14 shows that the hydrate deposition ratio for the higher flow rate (1350 kg/h) is larger than that for the lower flow rate (850 kg/h). A higher flow rate can lead to a larger hydrate deposition ratio and the flow rate effect is more significant under high water cut conditions. Hydrate deposition is a complex process that can be influenced by many parameters, so it would be difficult to only analyze the influence of flow rate without considering the effect of water cut. As we know, the hydrate deposition is a mass transfer process. More hydrates amount represents a larger mass transfer concentration, and more adhesive water gives a larger mass transfer efficiency. As the water cut increases, there would be more water can be used to form hydrates or act as the adhesive water, and thus the effect of the flow rate would be strengthened. To clarify the influence of the liquid flow rate on the hydrate deposition process, experiments were performed at five different flow rates with 1% AA and a 30% water cut. The results are shown in Figure 15. As the flow rate increases, both the hydrate deposition ratio and the deposit thickness first increase and then decrease. The maximum value occurs at a flow rate of 1650 kg/h. This experimental phenomenon can be explained as follows: Rao et al.15 proposed that hydrate deposition is a mass transfer process between 25


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the liquid bulk and the pipe wall surface, and the process should be related to the mass transfer coefficient at the pipe wall surface, which can be characterized by the Sherwood number. Sh D = 0 .023 Re 4D/ 5 Sc 1 / 3

where Re D is the Reynolds number and

Sc

(8)

is the Schmidt number. For a specific

system, a higher flow rate results in a larger Reynolds number, and a larger Reynolds number results in a larger Sherwood number in Equation (8). This indicates that the higher flow rate can strengthen the hydrate deposition process by enhancing the mass transfer coefficient at the pipe wall surface. Therefore, the hydrate deposition ratio increases when the flow rate increases from 600 kg/h to 1650 kg/h. However, an increasing flow rate can also enhance the flow shear rate at the pipe wall surface. A strong flow shear rate makes it difficult for hydrate particles to adhere on the pipe wall and could even cause the deposition layer to break off. This flow rate effect has also been proposed by several researchers, such as Majid25, Vijayamohan1718

and others. Results of the experiments with a 1900 kg/h flow rate are shown in

Figure 16. Hydrates depositing on pipe wall surface can narrow the slurry flow area, and thus the flow shear rate at the deposit surface increases rapidly during the hydrate deposition process. When this surface flow shear rate reaches a critical point, the deposit will begin to slough. The surface shear rate can be estimated by the following method: 26


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For laminar flow in horizontal pipe, the flow shear rate can be calculated using:

µγ 2πrL = ∆Pπr 2

(9)

∆Pπr 2 ∆ Pr = 2µπrL 2 µL

(10)

γ=

where r is the flow radius (m), L is the pipe length (m), ∆P is the pressure drop (Pa), γ is the flow shear rate (s-1), and µ is the slurry viscosity (Pa*s).

According to the Darcy Formula, ∆P can be obtained with:

∆P =

64 ρLV 2 Re 2 D

(11)

Equation (11) can be substituted into Equation (10) to obtain

γ=

4V r

(12)

Using Equation (12), we can estimate the flow shear rate at the hydrate deposit surface:

γ' =

4V R −δ

(13)

where γ ' is the shear rate at the deposit surface (s-1), R is the pipe radius (m), and

δ is the deposit thickness (m). From Figure 16 we can see that the value of this critical surface shear rate is between 610 s-1 to 655 s-1 in our experimental system. It can be used as a factor to judge whether the deposit sloughs or not. Also, it can be used to identify the effect of 27


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flow rate. If the surface shear rate is smaller than this value, hydrate sloughing will not occur and the hydrate deposit amount will increase as the flow rate increases; otherwise, the slurry flow is very likely to break off the deposit layer and then the deposition amount will decrease with the increasing flow rate. It should be noted that this value is suitable for our experimental system and may vary with different experimental materials and apparatuses.

Based on the above discussion, the hydrate deposition process is essentially controlled by five factors: the hydrate formation driving force, the amount of adhesive water, the surface property (or AA concentration), the surface mass transfer coefficient and the flow shear rate. A schematic diagram of the influences of the different factors is shown in Figure 17.

5. Conclusions Hydrate deposition is a key problem in the hydrate formation and transportation process. A series of experiments were conducted to study the hydrate deposition mechanisms in W/O emulsion systems using a high-pressure flow loop.

First, the hydrate deposition process was observed through a glass window, and the process can be divided into four steps: (1) the hydrate formation and deposition, (2) the deposition layer sloughing, (3) the secondary hydrate formation and redeposition (inferred from the density data), and (4) annealing (suggested). Then, a quantitative method was proposed to quantify the hydrate deposition amount based on 28


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the variations in the slurry density. Finally, the influences of the different experimental factors on the hydrate deposition process were discussed. The hydrate deposition process was less severe with a higher driving force, higher AA concentration and lower water cut. The flow rate can promote the hydrate deposition process if the rate is not high enough, and when the rate is larger than a critical value, it can reduce the hydrate deposition amount via the strong flow shear force, which can break off the hydrate deposits.

ACKNOWLEDGMENT The authors wish to thank the National Natural Science Foundation of China (51534007), National Science and Technology Major Project (2016ZX05028-004001, 2016ZX05066005-001), National Key Research and Development Plan (2016YFS0303704), and Science Foundation of China University of petroleumBeijing (No.C201602) for financial assistance towards this work.

REFERENCE 1. Sloan, E. D.; Koh, C. A., Clathrate hydrates of natural gases. 3rd ed.; CRC Press: Boca Raton, FL, 2008; p xxv, 721 p., 8 p. of plates. 2. Sloan, E. D.; Koh, C. A.; Sum, A., Natural gas hydrates in flow assurance. Gulf Professional Publishing: 2010. 3. Sum, A.K., Koh, C.A., Sloan, E.D. A comprehensive view of hydrates in flow assurance: Past, Present, and Future, Proceedings of the 8th International Conference on Gas Hydrates, Beijing, 29-July, 2014. 4. Hatton, G.; Kruka, V., Hydrate blockage formation-Analysis of Werner Bolley field test data. DeepStar CTR 2002, 5209-1.

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5. Lingelem, M.; Majeed, A.; Stange, E., Industrial experience in evaluation of hydrate formation, inhibition, and dissociation in pipeline design and operation. Annals of the New York Academy of Sciences 1994, 715, (1), 75-93. 6. Nicholas, J. W.; Dieker, L. E.; Sloan, E. D.; Koh, C. A., Assessing the feasibility of hydrate deposition on pipeline walls—Adhesion force measurements of clathrate hydrate particles on carbon steel. Journal of colloid and interface science 2009, 331, (2), 322-328. 7. Aspenes, G.; Høiland, S.; Borgund, A. E.; Barth, T., Wettability of petroleum pipelines: Influence of crude oil and pipeline material in relation to hydrate deposition. Energy & Fuels 2009, 24, (1), 483-491. 8. Aspenes, G.; Høiland, S.; Barth, T.; Askvik, K. M.; Kini, R. A.; Larsen, R., Petroleum hydrate deposition mechanisms: The influence of pipeline wettability. 2008. 9. Nicholas, J. W.; Koh, C. A.; Sloan, E. D.; Nuebling, L.; He, H.; Horn, B., Measuring hydrate/ice deposition in a flow loop from dissolved water in live liquid condensate. AIChE journal 2009, 55, (7), 1882-1888. 10.Nicholas, J. W.; Koh, C. A.; Sloan, E. D., A preliminary approach to modeling gas hydrate/ice deposition from dissolved water in a liquid condensate system. AIChE journal 2009, 55, (7), 1889-1897. 11.Singh, P.; Venkatesan, R.; Fogler, H. S.; Nagarajan, N., Formation and aging of incipient thin film wax‐oil gels. AIChE Journal 2000, 46, (5), 1059-1074. 12.Le Gall, R.; Grillot, J.; Jallut, C., Modelling of frost growth and densification. International Journal of Heat and Mass Transfer 1997, 40, (13), 3177-3187. 13.Hernandez, O.; Hensley, H.; Sarica, C.; Brill, J.; Volk, M.; Delle-Case, E. In Improvements in single-phase paraffin deposition modeling, SPE Annual Technical Conference and Exhibition; Society of Petroleum Engineers: 2003. 14.Balakin, B.; Hoffmann, A.; Kosinski, P., Experimental study and computational fluid dynamics modeling of deposition of hydrate particles in a pipeline with turbulent water flow. Chemical Engineering Science 2011, 66, (4), 755765. 15.Rao, I.; Koh, C. A.; Sloan, E. D.; Sum, A. K., Gas hydrate deposition on a cold surface in water-saturated gas systems. Industrial & Engineering Chemistry Research 2013, 52, (18), 6262-6269. 16.Grasso, G. A., Investigation of hydrate formation and transportability in multiphase flow systems. PhD Thesis. Colorado School of Mines: 2015.

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17.Vijayamohan P, Majid A, Chaudhari P, Sum AK, Koh CA, Dellacase E, Volk M. Understanding gas hydrate growth in partially dispersed and water continuous systems from flowloop tests. In Offshore Technology Conference 2015 May 4. OTC25661. 18. Vijayamohan P, Majid AA, Chaudhari P, Sloan ED, Sum AK, Dellecase E, Volk M, Koh CA. Gas Hydrate Formation & Interactions for Water Continuous & Partially Dispersed Systems. In Offshore Technology Conference 2016 May 2. OTC27277. 19. Chen, G. J.; Li, W. Z.; Li, Q. P.; Sun, C. Y.; Mu, L.; Chen, J.;Peng, B. Z.; Yang, Y. T.; Meng, H. China Patent 201110096579.2,2011. 20. Chen, J.; Wang, Y.-F.; Sun, C.-Y.; Li, F.-G.; Ren, N.; Jia, M.-L.; Yan, K.-L.; Lv, Y.-N.; Liu, B.; Chen, G.-J., Evaluation of Gas Hydrate Anti-agglomerant Based on Laser Measurement. Energy & Fuels 2014, 29, (1), 122-129. 21. K.-L. Yan, C.-Y. Sun, J. Chen, L.-T. Chen, D.-J. Shen, B. Liu, M.-L. Jia, M. Niu, Y.-N. Lv, N. Li, Z.-Y. Song, S.-S. Niu and G.-J. Chen. Flow characteristics and rheological properties of natural gas hydrate slurry in the presence of antiagglomerant in a flow loop apparatus. Chem. Eng. Sci., 2014, 106, (3), 99–108 22. Shi, B.H., Chai, S., Wang, L.Y., Lv, X., Liu, H.S., Wu, H.H., Wang, W., Yu, D. and Gong, J. Viscosity investigation of natural gas hydrate slurries with antiagglomerants additives. Fuel, 2016, 185(12), 323-338. 23. Mettler-Toleda LasentecProduct Group. FBRMD600 hardware manual: powerful data collection and interpretation. Redmond (WA USA): Mettler-Toleda AutoChem, Inc; 2010. 24. Lv YN, Sun CY, Liu B, Chen GJ, Gong J. A water droplet size distribution dependent modeling of hydrate formation in water/oil emulsion. AIChE J. 2017 63(3):1010-1023. 25. AA-Majid A, Lee W, Srivastava V, Chen L, Grasso G, Vijayamohan P, Chaudhari P, Sloan ED, Koh CA, Zerpa L. The Study of Gas Hydrate Formation and Particle Transportability Using A High Pressure Flowloop. In Offshore Technology Conference 2016 May 2. OTC-27276. 26.Aspenes, G.; Dieker, L.; Aman, Z.; Høiland, S.; Sum, A.; Koh, C.; Sloan, E., Adhesion force between cyclopentane hydrates and solid surface materials. Journal of colloid and interface science 2010, 343, (2), 529-536. 27. Aman ZM, Sloan ED, Sum AK, Koh CA. Lowering of clathrate hydrate cohesive forces by surface active carboxylic acids. Energy & Fuels. 2012, 26(8):5102-5108. 31


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28. Aman ZM, Sloan ED, Sum AK, Koh CA. Adhesion force interactions between cyclopentane hydrate and physically and chemically modified surfaces. Physical Chemistry Chemical Physics. 2014,16(45):25121-25128. 29. Sonin, A. A., T. Palermo, and A. Lubek. "Effect of a dispersive surfactant additive on wetting and crystallisation in a system: water-oil-metal substrate. Application to gas hydrates." Chemical Engineering Journal 69.2 (1998): 93-98. 30. Nicholas, J. W., Inman, R. R., Steele, J. P. H. et al.. A modeling approach to hydrate wall growth and sloughing in a water saturated gas pipeline. Proceedings of the 6th International Conference on Gas Hydrates,Vancouver, British Columbia, Canada, July 6-10, 2008. 31. Esmail, Shefaza, and Juan G. Beltran. "Methane hydrate propagation on surfaces of varying wettability." Journal of Natural Gas Science and Engineering 35 (2016): 1535-1543. 32. Aman ZM, Dieker LE, Aspenes G, Sum AK, Sloan ED, Koh CA. Influence of model oil with surfactants and amphiphilic polymers on cyclopentane hydrate adhesion forces. Energy & Fuels. 2010, 24(10):5441-5.

Table 1 Composition of the civil natural gas Composition

Mol %

Composition

Mol %

N2

1.53

C3

3. 06

CO

2.05

iC4

0.33

CO2

0.89

iC5

0.04

C1

89.02

nC6+

0.01

C2

3.07

--

--

Table 2 Composition of the -10# diesel Composition

Mol %

Composition

Mol %

C7

1.05

C15

4.86

C8

0.92

C16

4.37

C9

4.6

C17

4.64

C10

11.4

C18

5.63

32


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C11

11.73

C20

10.74

C12

12.24

C24

9.77

C13

9.94

C28+

1.28

C14

6.9

--

--

Table 3. List of experiments

Exp.

Temp. (°C)

P (MPa)

AA (%)

Water content (%)

Q(kg/h)

1-4 5-8 9-11 12-14 15-16 17 18-21 22-25

-3,0,3,5 0 0 0 0 0 0 0

6 5,6,7,8 6 6 6 6 6 6

1 1 0,1,3 0,1,3 0,3 0 1 1

30 20 10 15 20 30 10,15,20,30 30

1350 1350 1350 1350 1350 1350 850 600,1150,1600,1900

(a)

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T07

P05

FBRM probe & PVM probe

Separator

Ft02

T08

NDR1 Megnetic centrifugal pump

P01 T06 T01

pressure reducing valve

T02

Mixer

P02

Ft01

Ft03

DP4 DP01

Jacket

Sight glass P03

Gas supply line

P07

T03

P04 DP02 T05

NDR2 P06

Buffer tank

DP03

Chiller

T04

Gas supply

Compressor

Gas charge line Liguid charge line P-3

P-2

Instrument codes P: Pressure Transducer ；DP: Differential pressure ； T: Temperature Transducer NDR: Nuclear Densitometer Ft: Mass flow meter

(b) Figure 1. (a)Photograph of the flow loop test section; (b) Process flow diagram of the flow loop

Figure 2. PVM images of different water cuts without AA

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Figure 3. PVM images of different water cuts with 1% AA

(a)

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(b) Figure 4. Results of the experiment at 6 MPa and 5°C: (a) Changes in the temperature, flow rate and liquid density over time; (b) Comparison between the calculated density and measured density and changes in the counts of particles larger than 100 µm over time

(a)

(b)

(c)

(d)

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(e)

(f)

Figure 5. Video images of the hydrate deposit: (a) 2:20:18; (b) 2:50:08; (c) 3:20:23; (d) 4:18:35; (e) 5:25:28; (f) 12:35:16

Figure 6. Hydrate growth process proposed by Lv et al.24

Figure 7. PVM images of the final stage of the experiments

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Figure 8. Phase equilibrium curve of the natural gas used in this work

Figure 9. Changes in the deposition ratio with different water bath temperatures in the experiments carried out at 6 MPa with a 1% AA addition, 30% water content and 1350 kg/h flow rate

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Figure 10. Changes in the hydrate deposition with pressure

Figure 11. PVM images of the hydrate formation and growth process: (a) before hydrate

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formation; (b) hydrate shell formation on water droplets; (c) formation of the hydrate/water masses; (d) and (e) hydrate/water mass reaction and growth; (f) final stage of the experiment

Figure 12. Changes in the hydrate deposition ratio with different AA concentrations

\

Figure 13. Hydrate particle chord length distributions for different water cut conditions: left top10% water cut; right top-15% water cut; left bottom-20% water cut; right bottom-30% water cut

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Figure 14. Changes in the deposition ratio with different water contents and flow rates

Figure 15. Changes in the hydrate deposition ratio at different flow rates in a 30% water content system

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Figure 16. Hydrate deposition and sloughing in the experiment with a 1900 kg/h flow rate

Figure 17. Schematic diagram of the influencing factors in the hydrate deposition process

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O) Emulsion

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