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Hydrate formation and plugging mechanisms in different gas-liquid flow patterns Lin Ding, Bohui Shi, Xiaofang Lv, Yang Liu, Haihao Wu, Wei Wang, and Jing Gong Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.6b02717 • Publication Date (Web): 14 Mar 2017 Downloaded from http://pubs.acs.org on March 16, 2017

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Industrial & Engineering Chemistry Research

Hydrate formation and plugging mechanisms in different gas-liquid flow patterns Lin Dinga, Bohui Shia*, Xiaofang Lva,b, Yang Liua, Haihao Wua, Wei Wanga, 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 Corresponding author’s email: [email protected] Abstract: As oil/gas exploitation moves into deep water, hydrate formation and plugging in flowline has been a main concern of the flow assurance engineers. A series of experiments were conducted in a gas-emulsion multiphase flow system using a high pressure flow loop. The properties of hydrate agglomeration and deposition in different flow patterns were investigated. Firstly, based on the hydrate chord length distribution and the changes of slurry density, several methods were proposed to quantitatively estimate the hydrate agglomeration degree and deposition degree. Secondly, typical results in each flow pattern were analyzed and the plug formation mechanisms in each flow pattern were proposed. Then, after comparing the results in each flow pattern, it was found that the order of hydrate agglomeration degree from 1

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high to low is: slug flow, stratified flow, bubble flow and annular flow; and the order of hydrate deposition degree from high to low is: annular flow, slug flow, bubble flow and stratified flow. Key words: hydrates; multiphase flow; agglomeration; deposition; mechanisms; flow patterns;

1. INTRODUCTION Natural gas hydrates are complex crystalline, ice like solids formed by natural gas molecules and water under low temperature and high pressure.1 In recent years, as the development tendency of petroleum industry moves to deep water, hydrates have been a major hazard to the flow assurance of subsea transportation systems.2 Hydrates formation in the pipeline can increase the pressure loss, make the flow more complex and unpredictable, and may even block the pipeline.3 Traditional ways of hydrates prevention, including pipeline insulation, pressure reduction and thermodynamic inhibitor injection, have been used for decades in field production. But the traditional ways are of great economic costs that may become extremely unacceptable in future field production with high water cut. Anti-agglomerant is an alternative approach in the hydrate management strategy, which allows hydrates to form but prevents their agglomeration.4 In this condition, the system forms a slurry flow in flowline. In this approach, the hydrate slurry must have good fluidity and must not block the flowline. Therefore, to promote a better application of the hydrate risk management strategy, two key problems have been widely investigated: hydrates formation kinetics5-12 and 2


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hydrates slurry flow properties.13-20 At present, most of these studies focus on the water or water/oil emulsion system and very few of them involve gas-liquid two phase flow, which is the most common system in subsea pipeline transportation. So, the interaction effect between hydrate formation and the gas-liquid multiphase flow, especially the plug mechanism in different flow patterns, is an important problem to be solved. In the past few years, some studies have been done to investigate the influence of hydrate formation on multiphase flow property. In experimental aspect: Joshi et al.21 observed in experiments for the first time that the formation of a small quantity of hydrates may immediately lead to slug flow onset in a system near the stratified/slug flow or bubble/slug flow transition point. This is the first evidence that hydrate can affect the flow pattern transition in multiphase flow systems. Then, to further identify that whether hydrate formation influences the flow pattern transition, Lv et al.22 studied the flow pattern of gas-slurry flow with hydrate particles on a high pressure flow loop with 1 in internal diameter. Their results revealed that the Mandhane flow pattern map could not predict the gas-slurry flow pattern efficiently, and this indicated that hydrate formation did affect the flow pattern transition apparently. However, because the Mandhane flow pattern map has a great dependence on the experimental apparatus and materials, it is likely that the results of Lv et al. may not reflect the influence of hydrate formation accurately. Then, Ding et al.23 conducted a series of flow loop experiments and made two flow patterns maps, one with hydrate particles and the other one without hydrate particles. Through the comparison between these 3



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two flow pattern maps, they confirmed that the hydrate formation would cause three main changes of the flow pattern map: (i) the area of stratified smooth flow decreases and the stratified smooth flow will transform into slug flow or stratified wave flow at smaller gas/liquid velocities; (ii) the boundary of the annular flow moves a little to the left, meaning that the slug flow and stratified wave flow will transform into annular flow at smaller gas velocities; (iii) the boundary between the slug flow and bubble flow slightly moves down and it is easier for the slug flow to transform into bubble flow. Besides, in model research aspect: Zerpa et al.

24

established a hydrodynamic slug

model that considered gas-liquid-hydrates flow in gas-water system. Their results indicated that the hydrate formation would induce a flow regime transition from stratified flow to slug flow, which was consistent with the experimental observation of Joshi.21 Then, Hegde et al.25 used the model established by Zerpa et al.24 to predict the effects of hydrates on the slug characteristics, such as the slug length distribution, number of slugs, and slug frequency. Their results showed that the liquid-hydrate slip, hydrate volume fraction and hydrate aggregation affected the slug characteristics significantly. Then, Rao et al.26 used a hydrodynamic slug model coupled with a transient hydrate formation model to simulate the gas-liquid flow in subsea pipeline. This model can predict the flow regime transition among stratified flow, stratified wave flow, slug flow and bubble flow, both with and without hydrate particles. The above studies have uncovered the mechanisms of how hydrate formation influences the multiphase flow properties, and effective models have been proposed to 4


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predict the flow property variation. However, for the influence of different multiphase flow factors on hydrate formation kinetics, there are very few relevant studies. Lv et al.22 studied the influence of gas/liquid flow rates on gas-slurry flow pressure drop and found that the influence of liquid superficial velocity on the pressure drop was more obvious than that of the gas superficial velocity in stratified flow. But they did not clarify the influence of gas/liquid flow rates on hydrate formation kinetics, which is very important in modifying the hydrate growth model in multiphase flow systems. Lorenzo et al.27, 28 investigated the hydrate formation process in annular flow systems, their results confirmed that hydrates growth rate in gas dominant system was significantly larger than that in the water or oil dominant systems. This indicates that changing the gas/liquid flow rates (or gas/liquid volume fractions) can influence the hydrate formation rate. In addition, they also pointed out that, in annular flow, the plugging mechanism was dependent on the supercooling degree of the experimental system. Then, Cassar et al.29 conducted hydrate formation experiments in both annular flow system and stratified flow system. They found that in both systems the line blockage was reached after three steps: (1) rapid hydrate formation and growth, (2) hydrate formation rate slow down and (3) the increase of formation rate. And they also found that the gas-water flow pattern affected the hydrate formation rate and plugging time apparently. Hydrate plug formation mechanism is different in different flow systems, which has been studied by many researchers. Davies and Boxall et al.30 improved the 5



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hydrate formation and plugging mechanism proposed by Turner31 for oil dominant systems. They pointed out that, in oil dominant systems, hydrate would first form at the oil-water interface as hydrate shell. Then, the hydrate plug formed mainly due to the shell growth and the decrease of hydrate transportability, which was dependent on the pump speed and water cut. In addition, they simplified and improved the hydrate formation model, and found that the effective diffusivity and the hydrate–oil slip ratio were the most sensitive parameters with respect to the plugging tendency.32 For water dominant systems, Joshi et al.33 divided the hydrate plug formation process into three stages based on their experimental results: stage I consists of constant pump ∆P, stage II consists of a sharp increase in the pump ∆P, and stage III consists of large fluctuations in the pump ∆P. Then, they pointed out that the hydrate plug formation in water dominant systems was a consequence of the increase of hydrate concentration, which would further lead to the formation of hydrate bed and wall deposit. Mechanism of hydrate plug formation in gas dominant systems has been studied by Rao et al..34 They found that, in gas dominant systems, hydrate would deposit on the pipe wall, starting from nucleation to dendritic growth to annealing/hardening of the deposit. Also, they proposed a model to predict the hydrate deposition process, and results indicated that the hydrate thickness and the distance of plug formation length were significantly affected by the water saturation and fluids velocity. Hydrate plugging mechanisms in these three systems are briefly shown in Figure 1.

6


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Figure 1. Schematic diagram of hydrate plugging mechanism in different systems

Based on the above studies, mechanisms of how hydrate formation affect the multiphase flow properties have been well addressed, however, in turn, the influence of different multiphase flow parameters on hydrate formation kinetics are still unclear, especially the influence of different flow patterns on hydrate agglomeration and deposition properties. In the present work, a series of experiments were conducted using a high pressure flow loop. Hydrate agglomeration and deposition properties were studied and the plugging mechanisms in different flow patterns were proposed.

2. EXPERIMENTAL SECTION 2.1. High Pressure Hydrate Flow Loop The experiments in this work were conducted using a high pressure flow loop, which was constructed by the State Key Laboratory of Pipeline Safety in China University of Petroleum (Beijing). The loop consists of a centrifugal pump, a gas compressor, four test sections, a data acquisition system and several data sensors. The 7



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test section is 30m long in total and the internal diameter is 2.54cm. It is made from carbon steel and the design pressure is 15MPa. The working temperature of the flow loop ranges from -20°C to 100°C, which is controlled by four Julabo water baths with a precision of 0.01°C. Besides, the loop is equipped with 5 pressure sensors and 8 temperature sensors, with the precision of 0.01bar and 0.1°C respectively. It is also equipped with two flow meters, one for the liquid flow rate and the other one for gas flow rate. On the test section, a focused beam reflectance measurement (FBRM) probe and a particle video microscope (PVM) probe are quipped, which can help to study the size and behaviours of hydrates particles from a microscopic view. In front of the gas/liquid mixer there is a density meter, which can measure the changes of the slurry density. In addition, there are four glass windows equipped on the test section, from which we can directly observe the flow patterns and flow conditions in the pipeline. A photograph of the test section and a process flow diagram are shown in Figure 2.

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Figure 2 Top-Schematic diagram of the high pressure hydrate flow loop; Bottom-Photograph of the flow loop test section

2.2. Materials and Procedures The materials used in the experiments include civil natural gas from Shanjing Natural Gas Pipeline in China, deionized water, -20# diesel oil and AAs. For the composition of the gas and diesel oil, please refer to our previous work.23 The AA is not an industrial AA and it is extracted from a saponins plant that developed by the Chemical Engineering Department in China University of Petroleum- Beijing.35 The experiments were carried out with 10% water cut and 1% AAs dosage. The water cut was defined as the ratio of the water volume to the whole liquid volume. The AA dosage is defined as the volume fraction of AA additive in the water phase. The setting temperature of the water bath was 0°C. For each experiment, the flow pattern was confirmed through the observation from the glass window. The experiment list is shown in Table 1. 9



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Table 1 List of experiments Exp.

Flow

Qg

Ql

P

Exp.

Flow

Qg

Ql

P

No.

Pattern

(kg/h)

(kg/h)

MPa

No.

Pattern

(kg/h)

(kg/h)

MPa

1

Stratified

50

500

5

11

Slug

100

1100

5

2

Stratified

80

500

5

12

Slug

100

1100

5

3

Stratified

100

700

5

13

Slug

100

1100

5

4

Stratified

100

500

6

14

Slug

100

1100

6

5

Bubble

50

1200

5

15

Slug

100

1250

6

6

Bubble

50

1750

5

16

Slug

150

1100

5

7

Bubble

60

1100

5

17

Annular

180

450

5

8

Bubble

70

1800

6

18

Annular

260

400

5

9

Slug

120

1100

5

19

Annular

260

500

6

10

Slug

100

1100

5

The experimental procedure is briefly introduced as follows: (i) Vacuum the loop to -1 bar using a vacuum pump to eliminate the influence of air. (ii) Load the deionized water and diesel oil at a specified water cut. (iii) Inject natural gas into the loop to reach the experimental pressure. (iv) Circulate the liquid and gas by the pump and compressor, respectively. The gas/liquid flow rates can be adjusted to form different gas-liquid flow patterns, in which the hydrates will form in the next step. (v) When the monitored flow parameters reach a stable state, cool down the loop to form hydrates crystals. In this period, both the flow parameters and the hydrates particles behaviors are recorded. (vi) When all the collected data keep stable, increase the temperature to decompose the hydrates. Then, start another set of experiment in another flow pattern according to the above steps. 2.3 Methods of quantitative estimation for the hydrate agglomeration and deposition degree

10


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The main objective of this work is to study the hydrate agglomeration and deposition properties in different flow patterns, and then analyze the plugging mechanisms in each flow pattern. In this section, several methods were proposed to estimate the factor of hydrate agglomeration degree, fa, and the factor of hydrate deposition degree fd.

Figure 3. Changes of chord length distribution in Exp. 15

The first method to estimate fa is based on the critical chord length of hydrate agglomeration, Cc. Here we use the FBRM results of Exp. 15 as an example, which is shown in Figure3. The three lines in Figure 3 stand for the particles/droplets chord length distributions at three different time points in Exp. 15: just before hydrate formation (black line), 10 minutes after hydrate formation (red line) and the final state of the experiment (blue line). We can see that there is an intersection point of the three lines at about 40 microns, and we define this point as the critical chord length of hydrate agglomeration in Exp. 15. After hydrate formation onset, due to the agglomeration between hydrate particles and water droplets, the number of particles/droplets smaller 11



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than Cc decreased apparently, while the number of the particles/droplets larger than Cc increased rapidly. Thus, we use the changes of the percentage of hydrate particles lager than Cc to estimate the hydrate agglomeration degree: 0 f a = max ϕ Cc − ϕ Cc

(1)

where fa is the factor of hydrate agglomeration degree, ϕCc is the number 0 percentage of hydrate particles/water droplets larger than Cc, ϕCc is the number

percentage of water droplets larger than Cc before hydrate formation. However, this method is inapplicable for annular flow because no Cc occurred in annular flow experiments. FBRM results of Exp. 19 in annular flow is shown in Figure 4. After hydrate formation onset, all particles decreased in number and there was no intersection point of the three lines in Figure 4. This was because in annular flow hydrate formed mainly on the pipe wall surface in form of hydrate layer, so hydrate agglomeration in the bulk phase was not obvious. Therefore, another method is introduced to estimate the hydrate agglomeration degree which is based on the square-weighted mean chord length of hydrate particles, Cm. Changes of the Cm of in Exp. 19 is shown in Figure 5. We can see that the Cm increased rapidly after hydrate formation onset in annular flow. So we can use the increase of Cm to estimate the hydrate agglomeration degree, which can be calculated by

f a' =

max Cm − Cm0 Cm0

(2)

where f a' is the factor of hydrate agglomeration degree calculated by Cm, C m0 is the square-weighted mean chord length before hydrate formation onset. 12


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Figure 4. Changes of chord length distribution in Exp. 19

Figure 5. Changes of the square-weighted mean chord length in Exp. 19

Both of the above two methods can be used to estimate the hydrate agglomeration degree, and the results of these two methods are compared in section 3.4.

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Figure 6. Changes of the slurry density and particle number in Exp. 15

The method to estimate hydrate deposition degree is based on the changes of slurry density ρs. Here we also use the results of Exp. 15 as an example, which is shown in Figure 6. We can see from Figure 6, after the hydrate formation onset the total number of hydrate particles/water droplets, Np, decreased apparently and the number of particles larger than 100um, Np>100, increased rapidly, which indicated that the hydrate agglomeration occurred at this time. Then, Np>100 began to decrease gradually. This decrease of the large particles was not caused by the agglomerates breaking, because the total number of hydrate particles also decreased slightly instead of increasing at this period. Therefore, this was likely caused by the hydrate deposition on the pipe wall surface. In addition, it was worth noting that the slurry density, ρs, also decreased apparently after the hydrate formation. As we know, hydrate density is larger than that of the oil phase (about 740kg/m3), and the unconverted water which is encapsulated in the hydrate agglomerates may also deposit together with hydrates particles. Therefore, hydrate deposition can lead to a significant reduction of the slurry density. Thus, based 14


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on these two phenomena, we concluded that hydrate deposition occurred in this experiment. Here we use the level of the slurry density reduction to estimate the factor of hydrate deposition degree, fd, which is calculated by:

fd =

( ρ s −initial − ρ s − final ) ϕ H0

(3)

( ρ s −initial − ρ oil ) ϕ H

where ρ s−initial is the slurry density just before hydrate formation onset (kg/m3),

ρ s− final is the slurry density at the final state of the experiment (kg/m3), ρoil is the density of the oil phase (kg/m3), ϕ H is the total volume fraction of hydrates formed,

ϕ H0 is the hydrate volume fraction under the condition that the added water is totally converted into hydrates. The second item at the right side of the equation is to eliminate the influence of different hydrate formation amount on hydrate deposition process. The hydrate formation amount was obtained through the gas consumption amount, which was calculated by

ng =

P1V PV − 2 z1 RT1 z 2 RT2

(4)

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

V

is

gas volume in the separator (m3), z is compressibility factor in experimental pressure, R is gas constant (J/mol/K), T1 is temperature before hydrate formation (K), T2 is temperature after hydrate complete formation (K). Base on the gas consumption amount, the hydrate volume fraction can be calculated by: 15



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ϕH =

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ng M g + N * ng M w

(5)

ρ H VL

Where ϕ H is hydrate volume fraction, M g is hydrate molar mass (g/mol),

N

is

hydration number (5.85 for natural gas), M w is water molar mass (g/mol), ρ H is hydrate density (kg/ m3), VL is the total volume of the liquid phase (m3).

3. RESULTS AND DISCUSSION During the experiments, the flow patterns were confirmed by the visual observation through the glass windows and the following four flow patterns were studied in this work: stratified flow, bubble flow, slug flow and annular flow. In this section, typical results of the experiments in different flow patterns were presented and analyzed. Then, based on the analysis of the typical results, plugging mechanisms in different flow patterns were discussed. In addition, degrees of hydrate agglomeration and hydrate deposition in each flow pattern were compared. 3.1. Results in stratified flow Exp. 1-4 were carried out in stratified flow conditions and the results of these four experiments were similar. Here we use the results of Exp. 4 as an example to show the typical results in stratified flow.

16


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Figure 7. Results of Exp. 4 in stratified flow condition

As shown in Figure 7, the relative DP is the pressure drop of the flow loop divided by the liquid flow rate. When hydrate began to form at about 1.7h, the total number of hydrate particles/water droplets decreased rapidly, indicating the hydrate agglomeration occurred at this time. Due to the hydrate formation and violent agglomeration, the liquid flow rate decreased and the relative DP increased rapidly. After this period, both the relative DP and the liquid flow rate kept constant for about half an hour. Then again the liquid flow rate began to decrease and the relative DP began to increase. This was caused by the hydrate growth and accumulation in the liquid phase as we can see the total number of particles increased during this period. And finally, the loop was blocked, which is shown in Figure 8 (b). We can notice that the slurry density changed very little after hydrate formation, indicating that the hydrate deposition degree in stratified flow was very small. In addition, the total number of hydrate particles in liquid phase increased continuously after the initial 17



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agglomeration, which also meant the hydrate particles tend to grow in the liquid phase instead of depositing on the pipe wall surface. So the plugging in this experiment was mainly caused by the continuous growth and accumulation of hydrates in the liquid phase, as shown in Figure 8 (b).

(a)

(b)

Figure 8. (a) Hydrate formation and (b) hydrate plugging in stratified flow.

Based on the above analysis and the recorded picture, a plug formation mechanism in stratified flow is proposed, as shown in Figure 9: (i) The system stays at gas-liquid stratified flow with the water dispersed in oil phase as water droplets; (ii) When the system runs into hydrate stable region, hydrate nucleation onset; (iii) Hydrates particles and water droplets begin to agglomerate with each other; (iv) After the rapid agglomeration, the agglomerates grow continuously; (v) Hydrates accumulate in the liquid phase and then bedding on the pipe wall, and then the pipeline is blocked.

Figure 9 Schematic diagram of plugging mechanism in stratified flow (recreate from the diagram

18


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proposed by Turner31)

3.2 Results in bubble flow Exp. 5-8 were carried out with very small gas flow rates in order to form bubble flow conditions. Results in these experiments are similar and here we use the results of Exp. 5 as an example, which is shown in Figure 10.

Figure 10. Results of Exp. 5 in bubble flow condition

19



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Figure 11. Changes of mean chord length and number of particles in Exp. 5

As shown in Figure 10, after the hydrate formation onset at about 1.7h, the total number of particles/droplets/bubbles decreased rapidly, indicating that hydrate agglomeration occurred at this period. Due to the hydrate formation and agglomeration, the liquid flow rate decreased gradually and the relative DP increased rapidly. Then the total number of particles began to increase, which could be caused by several factors such as the breaking of hydrate-coated bubbles, the breaking of hydrate agglomerates or the hydrate continuous growth in liquid phase. Figure 11 shows the changes of the square-weighted mean chord length of the particles, which shows the similar trend with the change of total number of particles. This indicates that the increase of particles number is not caused by the agglomerate breaking or bubble breaking, since this would cause reduction of the mean chord length. So in this stage, hydrate grew continuously in the liquid phase. Then, the total number of particles began to decrease, along with the slurry density and liquid flow rate. From the reduction of the slurry density and 20


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particles number, we deduced that this was caused by the hydrate deposition on pipe wall surface. Then, the deposition process ceased and the system kept a stable state. No plug formed in this experiment. Based on the above results, hydrate formation and slurry flow process in bubble flow is proposed, as shown in Figure 12: (i) Water disperses in the oil phase as water droplets, and the system maintains at a stable bubble flow; (ii) When the system runs into hydrates stable region, hydrates begin to form on the water/oil interface; (iii) Hydrates particles and water droplets begin to agglomerate with each other, forming large agglomerates; (iv) Hydrates and agglomerates grow in the liquid phase; (v) Hydrates and agglomerates deposit on the pipe wall surface and then the system maintains a stable flow condition.

Figure 12 Schematic diagram of hydrates particles behaviors in bubble flow

3.3 Results in slug flow condition Exp. 9-16 were carried out in slug flow conditions. Results of Exp. 10 are used here to give an introduction of the typical results in slug flow, which is shown in Figure 13.

21



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Figure 13. Results of Exp. 10 in slug flow

Figure 14. Changes of mean chord length and number of particles in Exp. 5

Results of slug flow are similar with that of the bubble flow. When hydrates began to form, total number of particles/droplets decreased apparently in a very short time. This was caused by both the hydrate agglomeration in liquid phase and the hydrate deposition on pipe wall surface. Because we can see from Figure 13 and Figure 14, at this time, the slurry density decreased and also the square-weighted mean chord length 22


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increased rapidly. This indicated that the hydrate agglomeration and deposition occurred at the same time, which caused a large decrease of the liquid flow rate and a large increase of the relative DP. The deposition process in slug flow occurred much earlier than that in bubble flow and stratified flow. This was because slug flow had large flow fluctuations and thus the hydrate particles could be carried and contact with the pipe wall at high frequency. Therefore, deposition occurred immediately after hydrate formation onset in slug flow. This process lasted about 40mins and then the deposition process ceased as the slurry density almost kept constant. We can notice that, during this period, the mean chord length decreased a little and the total number of particles increased slightly. This indicated that some of the hydrate agglomerates brock up, which also led to a slight reduction of the relative DP. However, this phenomenon didn’t occur in every slug flow experiment and may not be regarded as the typical features of slug flow. Then the system kept a stable state till the end and no plug formed at last. Based on the above results, hydrate formation and slurry flow process in slug flow is proposed as shown in Figure 15: (i) The system maintains at stable slug flow with water droplets dispersed in the liquid phase; (ii) When the system runs into hydrates stable region, hydrates begin to nucleate on the water/oil interface; (iii)Hydrates and water droplets begin to agglomerate in the liquid phase and deposit on the pipe wall surface at the same time; (iv) Some of the agglomerates are broken up by the flow

23



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shear force (may not occur); (v) The system maintains a stable flow state and no plug formed in the flow loop.

Figure 15. Schematic diagram of hydrates particles behaviors in slug flow

3.4 Results in annular flow condition Exp. 17-19 were carried out in annular flow conditions, in which the liquid phase flows close to the pipe wall as annulus and the gas phase flows continuously in the center of the pipe. Results of Exp. 17 are shown in Figure 16.

Figure 16. Results of Exp. 17 in annular flow condition

As shown in Figure 16, the hydrate formation onset occurred at about 2.5hour. Then the slurry density and the number of particles decreased immediately. This was not because the hydrate deposition on the pipe wall, but because hydrates formed 24


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directly on the pipe wall surface. As a thick hydrate layer was observed on the inner surface of the pipe wall at this time, as shown in Figure 17(a). Because of the formation of this hydrate layer, the liquid flow rate decreased and the relative DP increased. Then both of the slurry density and the number of particles began to increase, and at the same time we observed that the formed hydrate layer began to slough, as shown in Figure 17(b). Then the liquid flow rate decreased to 0 and the loop was blocked in a very short time. Based on the changes of the slurry density and particles number and the recorded pictures in Figure 17, we deduced that the plugging was because the sloughed-off hydrate fragments accumulated in the pipe and was stuck at somewhere in the flow loop like the elbows or valves.

(a)

(b)

Figure 17. (a) Hydrate layer formed on the glass window; (b) hydrate film sloughing.

The plugging mechanism in annular flow is shown in Figure 18: (i) The system maintains at annular flow before hydrates formation. Some of the water disperses in the oil phase as water droplets, and some distributes as water film covering the pipe wall; (ii) Hydrates begin to form on the pipe wall or on the water/oil interface, forming a thick hydrate layer covering the pipe wall; (iii) The thick hydrate layer 25



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Page 26 of 33

begin to slough due to the intense flow shear force; (iv) The sloughed hydrate fragments accumulate at some uneven section and block the flow section.

Figure 18 Schematic diagram of plugging mechanism in annular flow (recreate from the diagram proposed by Sum et al.36)

3.5 Comparison of the results in each flow pattern In section 2.3, several methods were proposed to estimate the hydrate agglomeration degree and deposition degree. In this section, results in different flow patterns are compared, including the factor of hydrate agglomeration degree f a and f a' , the factor of hydrate deposition degree f d , and the hydrate volume fraction ϕ H . Detailed results are listed in Table 2. Table 2. Detailed results in each experiment Exp.

Flow

No.

Pattern

1

Stratified

ϕH

0.034

fa

0.3

f a'

0.86

fd

0.29

Exp.

Flow

No.

Pattern

11

Slug

26


ϕH

fa

f a'

fd

0.037

0.58

1.37

1.85

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2

Stratified

0.036

0.46

1.31

0.30

12

Slug

0.051

0.62

1.37

1.26

3

Stratified

0.046

0.56

1.79

0.31

13

Slug

0.046

0.58

1.30

1.03

4

Stratified

0.036

0.33

0.98

0.36

14

Slug

0.048

0.59

1.54

1.10

5

Bubble

0.043

0.4

1.09

0.81

15

Slug

0.048

0.64

1.77

1.40

6

Bubble

0.044

0.15

0.38

1.47

16

Slug

0.038

0.72

2.86

2.21

7

Bubble

0.046

0.34

1.16

0.53

17

Annular

0.014

/

0.49

1.90

8

Bubble

0.043

0.19

0.48

1.55

18

Annular

0.018

/

0.27

1.92

9

Slug

0.039

0.66

2.89

2.33

19

Annular

0.016

/

0.63

2.33

10

Slug

0.047

0.75

2.79

2.18

The volume fraction of hydrates formed in each flow pattern are shown in Figure 19. We can see that the hydrate volume fraction (or hydrate formation amount) in bubble flow and slug flow have the maximum value, both of which are about 4.4%. But the error range in slug flow is larger. The hydrate volume fraction in stratified flow is about 3.8% and hydrate volume fraction in annular flow is only about 1.6%. We should mention here that all the experiments in stratified flow and annular flow conditions were blocked at last. The plugging process in annular flow were very rapid while the plugging process in stratified flow occurred gradually. Because of the plugging, the length of the hydrate growth period is different in different flow patterns. Thus, the blockage is likely to be the reason for the difference of the hydrate formation amount. As we know, hydrate formation amount is mainly affected by the experimental pressure, temperature and the water cut. So as long as the flow system keeps a good 27



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flow stability, the hydrate formation amount in each flow pattern should be very close to each other.

Figure 19. Hydrate volume fraction in each flow pattern

The factors of hydrate agglomeration degree and deposition degree in each flow pattern are shown in Figure 20. f a is calculated based on the critical chord length and f a' is calculated based on the square-weighted mean chord length. We can see that, for

each flow pattern, the ratio of

f a'

fa

is almost a constant of 3, which demonstrates that

both of the above two methods are valid for estimating the agglomeration degree. The results show that these two factors have the same change tendency: slug flow>stratified flow>bubble flow>annular flow. This indicates that hydrates in slug flow have the largest agglomeration degree, which may be due to the unstable flow condition. Because slug flow has violent flow fluctuations, hydrate particles in slug flow can contact and collide with each other more frequently. Thus, the agglomeration degree is higher in slug flow. In annular flow, however, hydrates tend to form and grow directly

28


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on the pipe wall surface (Figure 17), so the agglomeration in liquid phase is not obvious. Therefore, the agglomeration degree in annular flow is the smallest.

Figure 20. Factors in different flow patterns

Also, Figure 20 shows that the change tendency of hydrate deposition degree is: annular flow>slug flow>bubble flow>stratified flow. As discussed above, in annular flow hydrates tend to form and grow directly on the pipe wall surface, which can lead to a higher deposition degree. For the stratified flow, because hydrate deposition mainly occurs at the liquid-solid interphase, while the liquid-solid interface in stratified flow is the smallest compared with other flow patterns. That is likely to be the reason why stratified flow has the smallest hydrate deposition degree.

4. CONCLUSIONS Experiments were carried out using a high pressure flow loop to investigate the hydrates behaviours and the slurry plugging mechanism in different flow patterns.

29



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Based on the changes of slurry density and the particle chord length distribution, new methods were proposed to estimate the degree of hydrate agglomeration and deposition in different flow patterns. Results showed that the agglomeration degree in order from high to low is: slug flow>stratified flow>bubble flow>annular flow; the deposition degree in order from high to low is: annular flow>slug flow>bubble flow>stratified flow. In addition, typical results of the experiments in different flow pattern conditions were presented. It was found that the slurry flow in stratified flow and annular flow conditions was easy to be blocked. The plugging in stratified flow was mainly due to the hydrates accumulation and bedding in the liquid phase, while the plugging in annular flow was mainly caused by the hydrate layer sloughing.

ACKOWNLEDGEMENTS This work was supported by the National Science Foundation for Young Scientists of China (Grant 51306208), National Natural Science Foundation of China (Grant 51274218 & 51534007), National Science and Technology Major Project (No.2016ZX05028004-001) and Science Foundation of China University of petroleum-Beijing (No.2462014YJRC006 & No.2462015YQ0404&No.C201602), which are gratefully acknowledged.

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