Article pubs.acs.org/EF
Study on Gas Hydrate Formation and Hydrate Slurry Flow in a Multiphase Transportation System Xiaofang Lv, Bohui Shi, Ying Wang, and Jing Gong* Technology National Engineering Laboratory for Pipeline Safety, China University of Petroleum, Beijing 102249, People’s Republic of China ABSTRACT: As oil and/or gas exploration and production enter deeper water, the flow assurance confronts challenges, one of which is the hydrate formation and blockage. Investigations about gas hydrate formation and hydrate slurry flow in a multiphase transportation system were performed on a newly constructed high-pressure experimental loop. On the basis of the experimental hydrate formation data, an inward and outward hydrate shell model was improved to predict the gas consumed amount during the hydrate formation process. With the help of a focused beam reflectance measurement and particle video microscope installed in this flow loop, the distribution of hydrate particles was observed, characterized in the coalescence and fragmentation. A “minimum safety flow rate” was first addressed for the safety of hydrate slurry flow in a multiphase transportation system. Then, the comparisons between our experimental data of the natural gas hydrate slurry flow pattern and the Mandhane flow pattern map revealed the influence of hydrate particles on the flow pattern of the slurry. Furthermore, the influence of the gas/liquid superficial velocity on the pressure drop was discussed at stratified flow for this gas hydrate slurry multiphase system.
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ments.18−26 These two types also have dissimilar experimental strategies, resulting in different experimental information about the hydrate nucleation, induction time, heat/mass transfer, etc. When it comes to the submarine multiphase flow system, the flow behaviors in the pipeline after hydrate formation are so complex that they diverge from the experimental results of autoclaves. Meanwhile, the study on multiphase flow characteristics (flow pattern, phase fraction, velocity of the phases, temperature, and pressure) is a prerequisite for the hydrate riskcontrol applications.27,28 Therefore, the approach in the loop could better simulate the actual conditions of subsea pipelines for the hydrate formation and slurry flow,18−26,29−32 whose experimental results could be applied to the hydrate slurry transportation for the deepwater mixture system. Therefore, investigations about gas hydrate formation and hydrate slurry flow in the multiphase transportation system have been performed on the high-pressure experimental loop newly constructed by the multiphase laboratory in China University of Petroleum, Beijing, China. First, an inward and outward hydrate shell model was used to predict the consumed gas amount during the hydrate formation process, which was considering the intrinsic kinetics and mass and heat transfer. Second, the “minimum safety flow rate” was addressed for the safety of hydrate slurry flow in the multiphase transportation system. Then, the comparisons between our experimental data of natural gas hydrate slurry flow pattern and the Mandhane flow pattern map33 revealed the influence of hydrate particles on the flow pattern of the slurry. Furthermore, the influence of gas/liquid superficial velocity on the pressure drop was discussed at stratified flow for this multiphase system.
INTRODUCTION Nowadays, the deepwater flow assurance confronts challenges along with the development of offshore oil/gas resource exploitation. Hydrate is one of the critical precipitates that has to be controlled in the subsea multiphase pipelines, which are commonly used for the oil/gas gathering and transportation. The controlling methods of hydrate include traditional inhibition and risk-control technique.1,2 In the traditional way, we can either inject the thermodynamic hydrate inhibitor3,4 (i.e., methanol or monoethylene glycol), heat (and/or insulate) pipelines,5 or reduce the pressure of pipelines6 to prevent the fluids falling into the hydrate-forming region. With the risk-control technique, the kinetic hydrate inhibitor7 can be applied in small amounts to extend the hydrate induction time by delaying the hydrate nucleation. The risk-control technique also includes the antiagglomerant (AA) method8,9 and the cold-flow technology without additional reagents,10,11 in which hydrate formation is permitted. AAs are chemicals that are designed to allow for hydrate formation but prevent adhesion of hydrate particles to each other. These generated hydrate particles are carried by the fluids in the pipeline to form a hydrate slurry flow, avoiding the hydrate plugging. The former, traditional, method is the main hydrate-control technology at present. However, because exploration and production are entering deeper water, thermodynamic hydrate-formation avoidance would reach its economic limits. The focus of flow-assurance strategies is thus shifting from the traditional to the risk-control technique. As one important study field of the risk-control technique, studies on hydrate formation and flow rules of the hydrate slurry are still in the period of theoretical development and experimental investigation. This current experimental science simulates practical engineering work, with the main approach being the hydrate slurry flow experiment. In general, the simulations could be classified (by the equipment) into the autoclave experiments 12−17 and the flow-loop experi© 2013 American Chemical Society
Received: August 18, 2013 Revised: November 17, 2013 Published: November 18, 2013 7294
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Figure 1. Schematic of the high-pressure hydrate flow loop.
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EXPERIMENTAL SECTION
Table 1. Composition of Gas Samples (mol %)
High-Pressure Hydrate Experimental Loop. The experiments have been conducted in a high-pressure hydrate flow loop29 (Figure 1) newly constructed at China University of Petroleum (Beijing, China) and dedicated to flow-assurance studies. The process temperature control ranged from −20 to 100 °C by four FP51-SL temperature controllers provided by Julabo Co., which have an average refrigeration capacity of about 1.5 kW from −20 to 20 °C. This cooling system can remove approximately 6.0 kJ of heat from the entire loop at normal operation to match the hydrate stability region. The pressure ranged from 0 to 15 MPa. The loop separately injects gas and liquid by a plunger compressor (2200 N m3 h−1) and a custom-made magnetic pump. The gas-injection point is the test-section inlet. At the outlet of the test section, gas and liquid are collected in an insulated separator (220 L) and are redirected toward the test section compressor and pump, respectively. Several tanks allow for the maintenance of the loop and separator pressure as hydrate forms. The 30 m stainless-steel test section consisted of two rectilinear horizontal lengths joined together to form a pipe with a 2.54 cm (1 in.) internal diameter and a 5.08 cm (2 in.) diameter jacket circulating a water/glycol blend that surrounded the test section. This experimental flow loop is equipped with several sensors. Thermocouples lie along the pipe, inside the separator, inside the water/glycol system, and on the different gas utilities. A Coriolis flowmeter (Endress and Hauser Company), with the measurement range from 0 to 3600 kg/h, measured the liquid mixture density and flow rate. Differential-pressure sensors along the loop followed the evolution of the linear pressure drop. Two FM1000 γ-ray densitometers were also available to measure the mean density of the multiphase fluid. Rapid data acquisition permitted detection of quickly occurring events, with a frequency of data acquisition up to 100 kHz and a frequency of data output at 1 Hz for the fluid temperature, pressure, pressure drop, flow, and other parameters. The errors of the logged experimental data were negligible. A focused beam reflectance measurement (FBRM) probe and a particle video microscope (PVM) probe are installed at the inlet of the test section, which allowed for the monitoring of the evolution of object droplets, bubbles, and solid particles carried inside the flow. Both of the probes window cut the streamlines at a 45° angle, beginning at the center of the pipe. Fluids. The testing used deionized water, civil natural gas from the Shan Jing Pipeline, and −20 diesel (Tables 1 and 2). The AAs used in
composition
mol %
composition
mol %
N2 CO CO2 C1 C2
1.53 2.05 0.89 89.02 3.07
C3 i-C4 i-C5 n-C6+
3. 06 0.33 0.04 0.01
Table 2. Composition of −20 Diesel Oil composition
mol %
composition
mol %
C11 C12 C13 C14 C15
0.89 3.36 5.38 6.2 6.78
C16 C17 C18 C19 C20+
6.83 7.99 7.46 6.38 48.73
this work are recompounded AAs containing Span20; thus, “AAs” are adopted throughout this paper. An electronic balance weighed the quantity of AAs (decrement method) with a measuring error of ±0.01 g, which is calculated according to various water-cut situations. A highpressure piston pump is used to inject the AAs into the flow system. The curve of hydrate formation for the defined natural gas composition is shown in Figure 2. Test Protocol. (1) The entire experimental loop is vacuumed until the vacuum degree reached 0.9 bar. (2) The loop is loaded with diesel and water (100 vol % liquid loading) considering the set water cut for each test. Here, water cut is defined as the volume fraction/ratio of water to the loading liquid (diesel + water), with the fixed diesel volume being 70 L during all of these experiments. The gas-supply unit begins to inject gas into the separator at room temperature (20 °C) until achieving the aimed experimental pressure. (3) The water and oil mixture is circulated at a constant flow rate to form a homogeneous and stable emulsion with the set AA dosage for each test. A certain flow rate varies with different experimental conditions, such as 0.6, 0.9, and 1.2 m/s involved in this work. The stability of water/oil emulsion referred to a relative stable process (dynamic stability) according to the measured data from FBRM under shearing action. This is to say that the emulsion is regarded stable when the average chord length of droplets fluctuated in ±0.2 μm within 2 h. (4) Under the initial 7295
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Figure 4. Schematic of the hydrate particle formation2 (Reproduced with permission from ref 2).
shell, to contact with water droplets (H/W). On the other hand, water molecules also have to be sufficient, which penetrate the shell by capillary suction from the outer surface of the shell to contact with the continuous oil phase (H/O) (Figure 5). Hydrate formation is an exothermic process, during
Figure 2. Hydrate formation curve of the testing natural gas. pressure and flow velocity, the temperature gradually decreases to the set value. During the hydrate formation process, the data acquisition system collects continuously about the temperature, pressure, pressure drop, flow rate, density, and chord length. (5) A round of experiments finishes at the end of the formation process when all measured data are stable, such as the system pressure and temperature. (6) Start the natural gas compressor in the loop and adjust the flow rates of gas and liquid phases at the inlet of the loop to perform flow experiments for the hydrate slurry multiphase system. (7) After the multiphase flow experiments, the dissociation of hydrate is carried out by increasing the temperature up to 30 °C. The system is kept in these conditions for 24 h with the aid of the particle size analyzer preparing for a next round. Hydrate Slurry Formation Process Description. In the natural gas + diesel + water system, the hydrate slurry formation process can be described as follows (Figure 3): first, the water phase in diesel was emulsified dispersion into the oil phase under shear function; second, when it reached the hydrate formation conditions, the gas dissolved in diesel would quickly react with droplets emulsified in the oil phase and then a thin hydrate shell formed on the surface of water drops (Figure 4) (the size of the particle/droplet did not vary substantially in this process);32 third, influencing factors (such as dynamics, heat transfer, mass transfer, and others) would restrict continuous hydrate formation with the proceeding of the reaction;34−36 and finally, formed hydrate particles may collide, aggregate, and even block the pipeline.
Figure 5. Schematic diagram of hydrate inward and outward growth shell model35 (Reproduced with permission from ref 35).
which this released heat exchanges with the surrounding environment. Therefore, once the pipeline pressure and temperature reach the condition of hydrate formation, hydrate starts to form, while hydrate continues to form only when the conditions (sufficient driving force for the crystallization kinetics, the continuous mass transfer of gas and water molecules, and rapid heat exchange of the hydrate formation) are satisfied simultaneously. Therefore, the growth parameters in the inward and outward hydrate shell growth model35 were improved on the basis of high-pressure hydrate slurry experiments in this paper. The difference between the fugacity of gas molecules under system pressure and hydrate equilibrium conditions was regarded as the driving force of crystallization kinetics for hydrate formation and growth. A mass conservation at the H/W interface was established by the balance between gas diffusion and consumption at this surface and the relationship of gas and water consumption because of the structure of the hydrate. A nonlinear in terms of the radius of the inner surface of the hydrate shell was deduced as eq 1. The volume of water derived by Hagen−Poiseuille flow permeated from the core of the water droplet to the outside of the hydrate shell was the key to predict the outward hydrate formation rate, which was calculated by eq 2. The temperature profile around the water droplet was predicted by the energy conservation equation. All
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RESULTS AND DISCUSSION Shell Model of Hydrate Formation. Hydrate formation is a multi-stage and system-dependent process, which is influenced by many factors, such as thermodynamics, kinetics, mass transfer, heat transfer, etc.34−36 It has great practical significance to establish a model describing the hydrate growth process in the multiphase transportation pipeline of multicomponents, in which the above-mentioned influencing factors could be integrally considered. In the process of continuous hydrate formation,37,38 on one hand, there has to be enough guest molecules through the shell, i.e., from the continuous oil phase to the inner surface of the
Figure 3. Schematic of the hydrate slurry formation and transportation1 (Reproduced with permission from ref 1). 7296
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of the details of this inward and outward hydrate shell model can be found in our previous paper.35 This model took into consideration the influencing factors of the hydrate formation and growth, such as thermodynamics, kinetics, and mass and heat transfer. Thus, its prediction can approach the hydrate formation in the actual hydrate slurry flow βM w dr − i = ρw dt
⎡ ⎢ ∑⎢ j=1 ⎢ ⎢⎣ N
ΩjC H/O, j − Ωeq, jCeq, j 1 K *j
+
(riΔt − 1)2 Ωj Df, j
(
1 riΔt − 1
−
1 roΔt − 1
)
⎤ ⎥ ⎥ ⎥ ⎥⎦
(1)
where Ceq,j and CH/O,j were the concentrations of component j at the three-phase equilibrium pressure and H/O interface, respectively, Df,j was the diffusivity of component j, Kj* only represented the kinetic rate constant of component j of the adsorption process, Mw was the molecular mass of water, N was the number of hydrate former gases, ri was the inner radius of −1 −1 the hydrate shell, rΔt and rΔt were the inner and outer i o radiuses, respectively, of the hydrate shell at the end of the last time step Δt − 1, t was the time, β was the hydration number, ρw was the density of water, and Ωj and Ωeq,j were the concentration parameter of component j at the system condition and the three-phase equilibrium pressure, respectively Vw,H/O =
Figure 7. Comparison of simulated and experimental gas consumptions with time at 30% water cut (5 MPa).
πεHσ Δt 4μw (roΔt − 1 − riΔt *)
(2)
where σ was the water/condensate oil interfacial tension, μw was the viscosity of water, εH was a porous parameter to describe the property of the hydrate shell, rΔt i * was the radius of the inner surface of the hydrate shell at the end of the calculated time step Δt only considering the inward hydrate growth, which was an intermediate variable and was not the final inner radius of the hydrate shell, and Vw,H/O was the total permeated water volume in the calculated time step Δt. Figures 6−8 show the gas consumption comparison between the experimental data and the results calculated by this model
Figure 8. Comparison of simulated and experimental gas consumptions with time at 30% water cut (6 MPa).
between the simulated results and experimental data at the three different pressures are 8.46% (4.0 MPa), 6.44% (5.0 MPa), and 10.81% (6.0 MPa), respectively. These deviations are all within the acceptable range in engineering. Hydrate Slurry Transportation. Typical Results of Hydrate Slurry Experiments. The typical tendency of system pressure, temperature, and gas consumption changed over time in the hydrate slurry formation process is shown in Figure 9. The pressure and temperature varied significantly in the process of hydrate generation: temperature increased notably with the boost in the number of hydrates, while the corresponding
Figure 6. Comparison of simulated and experimental gas consumptions with time at 30% water cut (4 MPa).
during the hydrate growth process at 30% water cut under different pressures. It can be known that the inward and outward hydrate shell growth model can be applied to simulate the hydrate growth rate and gas consumption in the hydrate slurry flow. The simulated results are in agreement with the experimental data. All of the absolute average deviations
Figure 9. Tendency of the pressure, temperature, and gas-consumed moles changed over time (the mean flow rate was 0.9 m/s). 7297
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pressure decreased substantially. Because of the further formation of hydrate, the gas consumption gradually increased yet with a gradually reduced consumption rate until the water in the system was completely conversed into hydrate. The decrease of the gas consumption rate here indicated that hydrate formation was limited by the heat/mass transfer, and it also proved the rationality of the hydrate shell inward and outward growth model.35 Figure 10 presents the square-weighted chord length as well as the no-weighted mean chord length for particles/droplets
Figure 12. In situ microphotography of hydrate particles formed in the stable period.
particles of the hydrate; on the other side, wettability of hydrate particles reduced and the degree of subcooling for the reaction increased along with the hydrate further formation, which resulted in the reduced cohesive force between hydrate particles. However, the continuous reduction of the particle size was not observed, while there were some periodic peaks of particle size local increase seen with almost constant periodicity. A similar behavior of the particle size was reported by Balakin et al.39 Actually, this periodicity was much longer to the mean circulation time of fluid in this flow loop, which strongly depended upon the mean flow rate. Obviously, the particle size would reduce by the enhanced fragmentation of agglomerates in the pump or even partial dissociation of hydrates. After several circulations of the fluid in the flow loop, the fragmented hydrate particles became smaller and smaller. This may probably cause some local hydrate particles to start to agglomerate with other adjacent particles, which might be the reason why the local increase of the particle size was observed with almost constant periodicity. Hydrate Slurry Transport Safety Testing. The purpose of injecting the AAs, one kind of the low-dose inhibitors, is to prevent aggregation of the hydrate particles blocking the pipeline. However, an interesting phenomenon is observed that the plugging time of the system with AAs is surprisingly earlier than a blank system (without AAs) at the same initial flow rate of 900 kg/h with water cut of 10% in the flow loop experiments (Figure 13). This is probably due to more hydrates formed and higher viscosity of the hydrate slurry reached with the addition of AAs. The addition of AAs can cause the water to emulsify uttermost and the interfacial area to increase concomitantly during the process of preventing hydrate particle aggregation. Therefore, at the same starting flow rate, the hydrate plug appeared earlier in the oil and water emulsion with the addition of AAs. It has to be noted here that this conclusion does not disprove the AA method for the flow assurance; this instead demonstrates that only the AA injection is not a surefire way for the safe transportation of the hydrate slurry. For the purpose of flow assurance, this phenomenon of forward plugging time with the addition of AAs at this flow condition is not pleased. AAs should be injected into the system to prevent the aggregation of hydrate particles, while the flow assurance should also be ensured. Then, lots of experiments were carried out, and it was
Figure 10. Trend of the particle chord length with time.
during the hydrate formation process for the water + diesel + natural gas system. The square-weighted chord length gives more weight to the longer chord length and is particularly well adapted to agglomeration phenomena, while the no-weighted mean chord length directly reflects the length changes for the particles/droplets (0.5−1000 μm) in the system. It can be seen from Figure 10 that the no-weighted mean chord length remained substantially constant (at 9 μm) before the hydrate generation. Once the hydrate started to form, the mean chord length of particles/droplets would rise immediately, which demonstrated the phenomena of collision and coalescence between particles/droplets during the hydrate formation (Figure 11). Thereafter, it tended to reduce with the further reaction (Figure 12). The main reasons for this decrease are the following: On one side, a stronger shearing action caused by the increased slurry viscosity broke the gathered large
Figure 11. In situ microphotography of hydrate particles formed in the initial period. 7298
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water cut, system pressure, and temperature. An initial flow rate that is greater than Qmin will ensure that the hydrate slurry remains in motion without plugging. Conversely, hydrate blockage will occur at a lower initial flow rate compared to Qmin. Therefore, preventing hydrate blockage at fixed parameters of subcooling, system pressure, water cut, AA dosage, etc. requires determining the critical minimum safe flow rate, Qmin. Any reducing of either the system temperature or flow rate could break this equilibrium, causing blockage.29 Natural Gas Hydrate Slurry Flow Pattern Map. The natural gas hydrate slurry flow pattern is fundamental with respect to the following pressure-drop model and the calculation of liquid holdup. The viscosity of the hydrate slurry is affected by many factors (such as the pressure, temperature, water cut, additive concentration, etc.); therefore, the flow pattern of the gas hydrate slurry multiphase flow varies under different circumstances. The flow patterns of the natural gas hydrate slurry system with 3 wt % AAs and different water cuts (i.e., 15, 20, 25, and 30%) were studied in this paper. Different flow patterns can be obtained by adjusting the mass flow rate of the gas−liquid phase. There were four flow patterns observed, including smooth stratified flow, wave stratified flow, short-slug flow, and slug flow, which were similar to the types of gas−liquid twophase horizontal flow patterns. The flow characteristic of the short-slug flow was an analogy of the slug flow pattern with a longer length of the liquid film and a shorter length of the liquid slug. Figures 15−18 show the comparisons between the
Figure 13. Flow rate of the hydrate slurry at different AA concentrations (900 kg/h, 4.0 MPa, and 10 wt %).
found that the initial flow rate was a key parameter to guarantee the flow assurance with the same holds of the addition of AAs. All of the mobility testing experiments revealed that an increasing pump speed improved slurry fluidity. For example, with a faster initial flow rate (1760 kg/h) at the same holds of AAs (3%) under the pressure of 4.1 MPa with 10% water cut, the flow rate would remain at about 523 kg/h after the completion of hydrates formed at the equilibrium condition. If the initial flow rate was set as 1684 kg/h with no changes of the other experimental conditions, plugging still occurred. Figure 14 illustrated this phenomenon by the temperature and flow
Figure 15. Flow pattern map of natural gas slurry flow experimental data at a water cut of 15% with the Mandhane flow pattern boundary. Figure 14. Trend of the temperature and hydrate slurry flow rate (1760 kg/h, 4.1 MPa, and 10 wt %).
experimental data of the gas hydrate slurry flow pattern obtained from the loop shown in Figure 1 and the Mandhane flow pattern33 commonly used in engineering work. The x axis is the gas superficial velocity, and the y axis is the slurry superficial velocity. The following can be seen from Figures 15−18: (1) The experimental stratified flow points were all in the stratified flow region divided by the Mandhane flow pattern map. However, the points of short slug flow and wave stratified flow were also in the stratified flow area, which meant that they cannot be effectively divided by the Mandhane flow pattern map. Meanwhile, the natural gas hydrate slurry data almost belonged to the stratified flow region when the gas superficial velocity was 0−1 m/s and the liquid superficial velocity was
