Article pubs.acs.org/EF
High-Pressure Rheology of Hydrate Slurries Formed from Water-inOil Emulsions Eric B. Webb, Patrick J. Rensing, Carolyn A. Koh, E. Dendy Sloan, Amadeu K. Sum,* and Matthew W. Liberatore* Center for Hydrate Research, Department of Chemical and Biological Engineering, Colorado School of Mines, Golden, Colorado 80401, United States S Supporting Information *
ABSTRACT: A unique high-pressure rheology apparatus is used to study the in situ formation and flow properties of gas hydrates from a water-in-crude oil emulsion. Viscosity and pressure of the hydrate slurry are measured during hydrate formation, growth, aggregation, and dissociation. The rheology of the hydrate slurries varies with time, shear rate (1−500 s−1), water content (0−50%), and temperature (0−6 °C). Hydrate slurry viscosity increases rapidly with time when hydrates form and then decays after going through a maximum as hydrate aggregates breakup or rearrange. Yield stress increases with annealing time up to 8 h and then remains constant. Hydrate slurry viscosity decreases with an increasing shear rate (i.e., they are shear thinning). Viscosity and yield stress both increase with an increasing water content. During dissociation, the viscosity increases just before the hydrate equilibrium temperature. Finally, transient viscosity measurements at varying temperatures suggest that mechanisms, such as cohesion forces and shear forces, competitively affect hydrate slurry viscosity.
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INTRODUCTION In subsea oil and gas pipelines, solid compounds called gas hydrates can form and completely block flow.1,2 Hydrates consist of small gas molecules (e.g., methane, ethane, propane, and carbon dioxide) encaged by water molecules. Gas hydrates are typically thermodynamically stable at high pressures and low temperatures (e.g., at 4 °C, CSMGem3−7 predicts that methane hydrate forms at 3.9 MPa). In one estimate, the oil and gas industry spends over U.S. $200 million annually on hydrate prevention8 or 5−8% of the total product plant cost.9 An understanding of the rheological properties of hydrate slurries in flowlines is essential in the management of hydrates and also a key component in developing strategies to prevent hydrate blockages. Flow of oil and gas in a pipeline often contains multiple phases, including water, oil, gas, hydrates, precipitated solids, and sand. This work will focus on multiphase flow with a continuous liquid oil phase, an emulsified water phase, and a gas phase. If the pressure and temperature are within the hydrate formation region, then hydrates will first form on the surface of the water droplets, at the interface between the oil and water, and then grow radially inward.1 If the droplets are small enough (3000
continuous phase is a complex mixture. Because we are unable to see inside the high-pressure cell, we are limited in conceptualizing the actual phenomena taking place during and after hydrate formation. Nonetheless, these results are the first step in demonstrating the potential of using a high-pressure rheometer to quantify hydrate slurry properties, which are critical in the management of gas hydrates in flowlines.
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Figure 8. Viscosity profile of hydrate slurries at different temperatures. The relative viscosity is defined as the measured viscosity divided by the emulsion viscosity just before hydrate formation. All systems contained 0.3 water volume fraction in WAC oil emulsion, initially charged to 1500 psig with methane gas. Measurements were performed with a shear rate of 100 s−1.
CONCLUSION Methane hydrates were formed in situ from water-in-crude oil emulsions in a high-pressure rheology apparatus. The viscosity, temperature, and pressure profiles of the slurry over time can identify hydrate formation, restructuring, and dissociation. The hydrate slurry viscosity increases to the peak value in about 20 min when hydrates form and then decays after going through a peak value as the hydrate suspension is continuously sheared. During hydrate formation, steady-state shear ramp, and dissociation, the hydrate slurry viscosity increased at all points as the water volume fraction increases. Yield stress of the hydrate slurry increases with an annealing time up to 8 h and then remains relatively unchanged. The yield stress gradually increases with the particle volume fraction until it dramatically increases at and above 0.5 water volume fraction. Also, all of the hydrate slurries shear thin. During dissociation, the slurry viscosity increases just before the hydrate equilibrium temperature. In summary, this study provides a collection of data to the growing field of hydrate slurry rheology. While many open questions remain to fully understand how hydrates are actually impacting the rheological behavior of the slurry, there is significant new insight from these systematic experiments and their results.
before hydrate formation. We also normalize the x axis, so that time zero corresponds to the start of hydrate formation at each temperature. As the experiment temperature is increased, the viscosity decreases for all points in time. Also, the initial slope and peak viscosity decrease as the temperature increases. A steep slope indicates rapid hydrate formation, because the driving force for hydrate formation increases as the temperature decreases. These measurements suggest that fewer hydrates were formed at the higher temperatures. Surprisingly, the viscosity shows a different trend after the peak viscosity for all three temperatures. At 0 °C, the slurry viscosity decreases after the spike, which, as discussed earlier, was suggested to be related to aggregate breakup. At 4 °C, there is a small and gradual increase in the slurry viscosity after the viscosity peaks initially. At 2 °C, the slurry viscosity seems to remain relatively constant after the initial viscosity peak, which suggests constant aggregate size. As discussed earlier, the slurry viscosity response after the peak is most likely related to restructuring of the hydrate suspension formed, because the pressure in the cell remains constant, indicating hydrates are no longer forming. One possible explanation of the different slurry viscosity dependence at the different temperatures can be related to the multiple forces competitively affecting the aggregation of the hydrate particles, possibly including shear forces and cohesion forces. Shear forces break up aggregates, while cohesion forces cause reaggregation. The shear forces should be nearly constant at all temperatures; however, cohesion forces will increase with increasing temperature.27,28 We also performed a few experiments using 3.5 wt % NaCl water instead of deionized (DI) water to make our emulsions. In these experiments, we did not observe significant differences in the salt system, except for the yield stress measurement (step 4). We performed three repeat experiments at 0.3 and 0.5 water volume fractions. Table 2 shows that the brine slurry has a much lower yield stress at 0.5 water volume fraction. This suggests that salt shifts the critical volume fraction for jamming the rheometer to a higher value. The complexity of these systems make the data interpretation quite difficult, because the crude oil used for the oil
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ASSOCIATED CONTENT
S Supporting Information *
Table of the composition of dead and live WAC oil. This material is available free of charge via the Internet at http:// pubs.acs.org.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected] (A.K.S.);
[email protected] (M.W.L.). Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS We acknowledge the support by the CSM Hydrate Consortium, which is presently sponsored by BP, Chevron, ConocoPhillips, ExxonMobil, Multichem, Nalco, Petrobras, Shell, SPT Group, Statoil, and Total. 3508
dx.doi.org/10.1021/ef300163y | Energy Fuels 2012, 26, 3504−3509
Energy & Fuels
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Article
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