Analysis of CO2 Hydrates in Crude Oils from a

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Analysis of CO2 hydrates in crude oils from a rheological point of view Gustavo Alonso Barrientos Sandoval, Edson José Soares, Roney L. Thompson, Renato do Nascimento Siqueira, Rafhael Milanesi de Andrade, Flavio B. Campos, and Adriana Teixeira Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02789 • Publication Date (Web): 02 Jan 2018 Downloaded from http://pubs.acs.org on January 3, 2018

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Analysis of CO2 hydrates in crude oils from a rheological point of view. Gustavo A. B. Sandoval,∗,† Edson J. Soares,∗,‡ Roney L. Thompson,∗,† Renato do Nascimento Siqueira,∗,¶ Rafhael Milanesi de Andrade,∗,‡ Flávio Campos,∗,§ and Adriana Teixeira∗,§ †COPPE, Department of Mechanical Engineering, Universidade Federal do Rio de Janeiro, Centro de Tecnologia, Ilha do Fundão, 21945-970, Rio de Janeiro, RJ, Brazil. ‡LABREO, Department of Mechanical Engineering, Universidade Federal do Espírito Santo, Avenida Fernando Ferrari, 514, Goiabeiras, 29075-910, ES, Brazil. ¶Department of Mechanical Engineering, Instituto Federal do Espírito Santo - Campus São Mateus, Rod. BR 101 norte, km 58, Litorâneo, São Mateus, ES, 29932-540, Brazil §CENPES, Petrobras, Rio de Janeiro, Brazil. E-mail: [email protected]; [email protected]; [email protected]; [email protected]; [email protected]; [email protected]; [email protected] Abstract Gas hydrates are crystalline solids formed by water and light molecules when a specific thermodynamic condition of high pressure and low temperature is attained. The formation of such structures can plug the production line, causing a shutdown with expensive consequences. In fact, besides waxy deposition, gas hydrate formation is among the hugest problems in flow assurance faced by the oil companies. High concentrations of CO2 have been reported in the Brazilian Pre-salt oil wells, with large

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potential to form hydrates, but to our knowledge, this kind of scenario has not been the subject of a deep rheological study. Here, we conduct a sequence of tests, using a high pressure rheometer system, to take into account the effects of water fraction and shear rate in the hydrate formation. We also investigate the ability of reconstruction of the hydrates and its memory effect. The main tests are displayed in terms of viscosity over time. By doing so, the hydrate formation is indicated by a viscosity jump.

Introduction Natural gas hydrates are crystalline water-based solids formed when high pressure and low temperature thermodynamic conditions are attained and the water hydrogen bonds (hosts) encage and hold one or more gas molecules (guests). Due to the solid crystalline structure of gas hydrates, they are substances that do not flow. 1 This situation must be considered in some circumstances like in drilling and extraction of oil and gas processes, or when the production of oil or gas is interrupted, because the formation of hydrates can plug the flow lines, causing expensive production shutdowns. In fact, this is one of the main problems faced by the oil and gas industry. 2 In the Brazilian oil and gas sector, it plays a challenging role, since many oil reserves are located in ultra-deep waters 3 , where the usual pressure and temperature conditions (approximately 4 o C and 100 bar) are in the hydrate formation zone, leading to a risky situation 1 . The major components in most production systems are methane, ethane, propane; in smaller quantity appear other hydrocarbons, besides nitrogen and CO2 . But in large reservoirs found in Brazil (Pre-salt region, for example) and in other parts of the world such as South Africa, fluids with very high levels of CO2 have been observed. In these cases, the CO2 content may achieve 0.7 mole fraction. Because it is a molecule different from the hydrocarbons usually found in oil production, and having different properties (such as higher solubility in water, for example), the present study can be considered an important path of investigation from the perspective of Flow Assurance in this kind of reservoirs. Hydrate formation occurs when the water emulsified in petroleum can be 2


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converted into ice slurries, which can cause an increase in viscosity that may be critical for the continuity of the flow. The rationale above justifies the attention given in the literature to the formation of hydrate suspensions in water-in-oil emulsions. One strategy usually taken by the oil industry to overcome this problem is to operate outside of the stable hydrate zone, using insulation, heating, dehydration or thermodynamic inhibitors. Another strategy is to continue working in the thermodynamically favorable hydrate zone and use LDH (low dosage hydrate) inhibitors, to avoid hydrate agglomeration or delay the hydrates formation. However, Tariq et al. 4 states that the adoption of the hydrates inhibition methods can reach up to 15 % of the total production cost. There is no doubt that a deeper understanding of the hydrate formation process is necessary and that experiments conducted in high-pressure rheometers (pressure cells) can significantly contribute to enlarge our knowledge on the subject. In these experiments, some quantities of the flow such as apparent viscosity, shear rate or shear stress can be directly measured under a diversity of conditions such as temperature, pressure and water cut, during the processes of induction, aggregation and dissociation of the hydrates. From a practical point of view, another important contribution of these experiments on small scales is to verify in which circumstances hydrates will form, anticipating what can happen in similar conditions of field operations and helping on hydrates formation prediction and prevention. Although several researchers have used rheometers to analyze the rheology of hydrates, in the majority of the cases, they use chemical substances, such as cyclopentane and tetrahydrofuran, in order to have measurements at atmospheric conditions, avoiding the inconvenience of working with high pressure levels 5–10 . Other few works have been carried out in flow loops 11–13 . In the specific case of pressure cells, only a limited number of investigations have been published and most of them used methane as guest molecule 14–20 . In this study, the tests were performed in a pressure cell, with carbon dioxide as guest molecule, since high concentrations of this gas have been reported in the braziian pre-salt oil wells, with large potential to form hydrates.

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Carbon dioxide is subcritical at hydrate forming conditions and has a relatively low vapor pressure, therefore, different phases such as a hydrate phase, a water rich liquid phase, an ice phase, a carbon dioxide-rich vapor phase and a carbon dioxide-rich liquid phase as well as two quadruple points can be found in the hydrate-carbon dioxide-water system 21 . At typical thermodynamic conditions of ultra-deep waters, CO2 hydrates are stable and the CO2 molecules are in the liquid phase 22 . For this reason, the hydrates slurries studied in this work were formed from water in oil emulsions with liquid CO2 . Chapoy et al. 21 indicated that for the CO2 -rich systems, initially there is a vapor + hydrate + liquid water line, then a vapor + liquid-rich CO2 + hydrate + liquid water line and finally a liquid-rich CO2 + hydrate + liquid water line. The bubble point of all these mixtures are higher than that of pure CO2 , hence hydrates would be more stable in the liquid-rich CO2 region, as the vapor + liquid-rich CO2 + hydrate + liquid water line is intersecting the bubble line at a higher temperature. Basically, at field conditions, water droplets are injected into the oil by turbulence or wave actions. These droplets can be stabilized by the oil viscosity and, on a long-term basis, by resins and asphaltenes 23 . Teng et al. 24 proposed that hydrate clusters (nucleation) form primarily in the water phase and, for CO2 droplets in high pressure and low temperature water, the concentration of hydrate clusters (crystallization) is highest at the CO2 –water interface. After crystallization, the particles of hydrates will agglomerate until forming a block and plug the pipeline. Some studies of hydrates formed from CO2 molecules have been performed in the field of refrigeration 25–28 , since this technology reduces the application of classic refrigerants with high global warming potential. In essence, this method allows cooling the refrigerants by exchanging heat with the help of secondary circuits 29 . Another strategy studied to reduce the global warming, through gas hydrates, is to capture and store the CO2 in order to reduce the atmospheric concentration of this gas 30–32 . Roughly, there are three different types of crystalline structure depending on the guest-molecule repulsion and on the pressure

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and temperature conditions can be formed: Structure I, II and H. The hydrates formed with CO2 molecules are known to form Structure I hydrates (two small and six large cavities) 21,25 . A novel method concerning hydrates formation was investigated by Song et al. 33 , in which CO2 is used not to form hydrates but to trigger the methane hydrates formation. To our knowledge, this is the first work that studies the rheology of hydrate slurries from water-in-oil emulsion with CO2 , during the induction, growth and dissociation periods.

Experimental Apparatus and Procedure Pressure cell system The high pressure rheometer system used to perform the experiments is shown in Fig. 1. The gas (CO2 ) is stored in a cylinder (1) at a pressure of 6 MPa. For experiments with pressures above that, a booster (2) is used to increase the pressure up to 40 MPa. A serpentine pipe (3) guarantees a constant supply of gas to the system and the volume of gas inside the pipe is 300 ml. A pressure valve (4) controls the pressure inside the rheometer (5). The tests were conducted in a shear stress controlled rheometer, Haake Mars 60 (Thermo Fisher Scientific), that allows the measurement in a large range of rotational speeds (from 10−8 rpm to 4500 rpm). The rheometer is connected to a thermostatic bath (6), Thermo Haake Phoenix II, to ensure an accurate temperature control during the experiments (from -20 to 150 0 C), with a heat/cooling rate of 0.6 0 C/min. The heating or cooling process occurs through the heat exchange between the measuring cup of the pressure cell and the jacket located at the base of the rheometer. After the test, a relief valve (7) is used to purge the system. The pressure cell (8) was specially designed to be used with the Haake rheometer. The cell consists of a rotor (9), which is the measuring geometry, and a stator (10). The stator has three connections: a rupture disc (11), for safety reasons, a pressure sensor (12) and the gas inlet (13). The rotor (35 mm of diameter and 80 mm of legth) is a cylinder concentric to the cup, forming a cup-and-bob assembly with 2mm of horizontal gap. It is important to 5


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Figure 1: Sketch of the high pressure rheometer system. note that the torque applied by the rheometer measuring head is not directly transmitted to the rotor but conveyed by a non-contact, concentric magnetic coupling (14). The inner magnet is located at the top of the measuring geometry and the outer magnet is attached to the shaft or the rheometer measuring head. The gap between the outer magnet and the cover of the stator is 2.9 mm wide. To diminish the friction of the rotor, two sapphire bearings (15) located at the bottom and at the top of the stator are used to support and guide the rotor inside the cell and the gap between the rotor and the stator is completely filled with 53 ml of emulsion.

Procedure The crude oil is heated for at least 2 h at 80 o C and cooled to room temperature. Next, deionized water is added to the cooled crude oil sample, while mixing at 8000 rpm for 3 min in a CAT X360 homogenizer. Our crude oil was provided by Petrobras and it is from a Brazilian pre-salt field. The emulsion was pressurized with CO2 , using our high-pressure system. In an attempt to fully saturate the oil phase with CO2 , the pressure cell was heated 6


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up to 80 o C. This temperature was retained for 8 h, keeping the rotor of the pressure cell at constant angular velocity. Next, the pressure cell was cooled to 4 o C, which is the working temperature. The majority of the tests was conducted at constant temperature, pressure and rotor angular velocity. Specifically, the pressure and temperature were fixed at 6 MPa and 4 o C, respectively. This thermodynamic state (work point) is marked at the CO2 hydrate equilibrium diagram in Fig. 2 (orange star), from where the subcooling, ∆T ≈ 6 0 C, can be deduced. It is important to note that the CO2 is in the liquid state, according to its phase diagram (marked by the green star in Fig. 2). This thermodynamic condition corresponds to the one commonly found in real applications.

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Equilibrium Curve of CO2 Working point

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Temperature [ºC] Figure 2: CO2 hydrate equilibrium diagram. In the upper left insertion is depicted our working point on the saturation curve of CO2 . To obtain confidence (trueness) in our experiments the equipments used during the tests 7


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like: pressure cell, thermostatic bath, pressure transducer, rheometer and other were calibrated and validated whit frequency. Also, repeatability tests were made whit different samples and in different days as exemplified in Figure 6. All our data are displayed in terms of viscosity over time. By doing so, it is possible to visualize the induction time, i.e., the time in which the beginning of hydrate nucleations are observed, evidenced by a peak of viscosity. The tests ended when the values of viscosity reached a steady state. Such a regime is characterized by an equilibrium between the mechanical shear and the restructuring hydrate forces, a typical mechanism of time-dependent materials.

Results and discussion Several tests were carried out to evaluate the effect of water fraction and shear rate on the induction of CO2 hydrates in two kinds of emulsion: with and without salt. We have also investigated the ability of reconstruction of CO2 hydrates after a certain period of time under rest at the same pressure and temperature of the initial test. Finally, we conducted a sequence of tests in order to evaluate the possibility of memory effects. Before the main experiments, we have conducted some tests to verify the accuracy of the pressure cell, since such kind of apparatus is not widely used yet and deserves a close attention, mainly because of the absence of a mechanical connection between the measuring device and the rotor (see Fig. 1). An important variable that must be previously set is the gap between the rotor and the pressure cell. The gap must be adequately chosen in order to levitate the rotor, a necessary condition for a reliable measurement. We have used a gap equal 2.9 mm in all our tests. In our preliminary tests, we verified the time required for the rotor stabilization and the accuracy of the pressure cell when concentric cylinders are used. The tests are displayed in Figs. 3, 4 and 5. In Fig. 3 the shear stress is shown as a function of time for three different values of shear

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rate. These tests were carried out with a 30 % of stable water in oil emulsion. Once the shear rate is set, the equipment takes around 1 s to stabilize the angular velocity and, after that, the shear stress keeps constant.

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30% W/O Emulsion Gap = 2.9 mm T = 4 ºC Geometry : Concentric cylinders

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140

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Time [s] Figure 3: Shear stress as a function of time for a 30% of w/o emulsion for different values of shear rate. Data is acquired until rotor stabilization is identified. The accuracy of the pressure cell when a Newtonian fluid is used is demonstrated in Fig. 4, where the shear viscosity is displayed as a function of shear rate. A soybean oil was used for this experiment. The dashed line is the value of the viscosity measured in a CannonFenske viscometer, which is a very precise device for Newtonian liquids. The symbols are the viscosity values measured by the pressure cell. The upper sapphire bearing needs to be lubricated before each test. The blue balls are the values of η with lubrication, also called friction correction, and the red triangles are the values of η without lubrication, or 9


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without friction correction. Clearly, the blue balls are closer to the dashed line. It is worth mentioning that the results become very inaccurate below a torque value of 450 × 10−6 Nm which is close to the lower limit of the equipment.

0.10 Soybean Oil Gap = 2.9 mm T = 25 ºC Geometry : Concentric cylinders

Shear Viscosity [Pa s]

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0.08

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Figure 4: Comparison of the concentric cylinders geometry, with and without friction correction with the Cannon-Fenske technique for the measurement of the shear viscosity of a soybean oil as a function of shear rate. Finally, we conducted the test displayed in Fig. 5 to definitely show the good accuracy of the pressure cell. The test procedure was the same used in 34 and 35 to take into account the yield stress of waxy crude oils. A sample of a dried oil was heated up to 50 o C and rested at this temperature for 20 min, before being cooled at a constant rate of 0.6 o C/min until 4 o

C is reached. The sample rested 2 h at 4 o C before the test beginning. In this condition, 10


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the waxy oil is a very complex viscoplastic material and the procedure used to measure its rheological properties is very typical (see 34 for details). What is worth noting here is that, for shear rates larger than 1 s−1 , the values of shear stresses measured with the pressure cell are quite close to those obtained with a rough plate–plate, which is a more adequate geometry to analyze such kind of material. Hence, it seems that the pressure cell can be used to satisfactorily take into account the shear viscosity when the shear rate is sufficiently high. Precisely, we must guaranty that torque applied is above the lower limit of the equipment.

102 Geometry : Concentric cylinders - Pressure cell Geometry : Rough plate - plate

Dried Oil

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Ti = 50 °C tTi = 20 min Tf = 4 °C tTi = 2 h R = 0.6 ºC/min

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Shear Rate [s-1] Figure 5: Shear stress as a function of shear rate: comparison between our pressure cell and the parallel plates. Figure 6 shows typical tests performed with an emulsion with water volume fraction of 30 %, where the viscosity is displayed over time at a shear rate fixed in 200 s−1 . In two curves, (blue triangles and orange squares), the samples were heated up to 80 o C, i.e. the 11


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conditions were the same for these two samples. The small difference between the curves can be considered a measure of confidence of our general results. A lower solubilization temperature test, where the emulsion was heated up to 40 o C, is shown in green balls. Since in this new case the evolution of viscosity over time was quite similar, we concluded that heating up to 40 o C was sufficient to fully saturate the CO2 . However, to be sure of the complete gas solubilization, we employed the higher temperature value of 80 o C. The period of solubilization was at least 8 h, when the values of viscosity were below 0.01 Pa.s and rather dispersed, because the torque required to keep the shear rate at 200 s−1 , at this level of viscosity, is close to the lower limit of our equipment. The viscosity does not change during the cooling process, until it reaches the equilibrium temperature, where it increases a little, but it jumps very fast when the temperature reaches 4 o C, after 10 hours of test. The exact time of jumping, i.e., the hydrates formation, is clearly seen in Fig. 7. It was around 20 min past 10 h in both tests. The viscosity changed in almost two orders, from below 0.01 to close to 0.5 Pa.s. The viscosity jump precisely marks the time of CO2 hydrate formation. The spike in viscosity is due to the aggregation of hydrate crystals, forming a strong structure which is kept by the reconstruction forces. Experiments with closed valve also shows the gas consumption, which is represented by the decrease of the pressure in the cell, also indicating hydrate formation. This result is depicted in Fig. 18. It was not possible to observe the hydrate formation by the temperature increment, as reported by, 36 because, as described previously, the temperature is measured in the jacket located at the base of the rheometer, instead of in the fluid, and the jacket temperature remains constant by the thermostatic bath. In the next three figures, we display our analysis of the effects of water fraction in the emulsion. The tests were carried out at constant shear rate (γ˙ = 200s−1 ) for four different water fractions, emulsions with 10 %, 20 %, 30% and 40 % of water in oil. Figure 8 shows the beginning of the test when the gas is fully solubilized in a water solution with 5 % of NaCl at constant pressure and temperature for 8 h. Over the period

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Time [h] H32 - Viscosity H32 - Temperature 80 °C

H36 - Viscosity H36 - Temperature 40 °C


Figure 6: Viscosity over time for emulsions of 30% w/o starting from two different initial temperatures (80 o C and 40 o C) keeping the same cooling rate and same final temperature (4 o C). of solubilization, the measured viscosity of all emulsions were bellow 0.01 Pa.s. The cooling started after 8 h and two hours later the temperature was around 20 o C, but the viscosity was yet below 0.01 Pa.s. The test temperature of 4 o C was reached in 10 h and 20 min and, less than 30 min later, the viscosity exhibited a sudden increase in the emulsions of 30 % and 40 %. For the emulsion of 20 %, the jump took more time, around 30 min. It occurred close to 11 h after the test beginning. It seems that the hydrate was not formed or its amount is too small in the emulsion with 10 % of water in oil and the viscosity increase was only 13


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Figure 7: Viscosity over time for emulsions of 30% w/o starting from two different initial temperatures (80 o C and 40 o C) keeping the same cooling rate and same final temperature (4 o C). related to the temperature decrease. The induction time is captured in Fig. 9, where only the data for the period between 10 and 16 h was displayed. The jump of viscosity for the emulsion with 20 % of water in oil is shifted to the right, i.e., the induction time is higher for this emulsion. 37 also observed a similar tendency for their water-in-oil emulsions. The complete test concerning the effects of water fraction in the emulsion is shown in Fig. 10. After a long enough time, the viscosity reaches a steady state, when the shear forces are in equilibrium with hydrate reconstruction forces. Such balance between these forces 14


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GABS

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Figure 8: Viscosity over time for different water volume fractions at a fixed shear rate: a close on the gas diffusion. Emulsions with 5 % of NaCl at 6 MPa and 4 o C. is typical from time-dependent materials and it will be discussed in more details later. As expected, the formation of hydrates increases with the water volume fraction, because more CO2 can be captured by the hydrogen bonds. Consequently, the viscosity enhancement is due to more aggregation among the hydrate particles. 19 suggested that the viscosity also increases as a consequence of the capillary bridges formed by the water between pairs of hydrate particles. It is also important to note the instabilities at the first instants after the hydrate induction for the emulsion of 40 % of water in oil. It seems that such instabilities are an increasing function of water fraction. In fact, the emulsions with NaCl and with water

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fractions above 30 % were unstable, what means that the average drop diameter was above the upper limit in which an emulsion is stable at rest. Most of the tests were carried out with water fractions below 30 % of water in oil. These viscosity instabilities, shown for the emulsion of 40 % of water in oil, after the hydrate formation, were also noted by. 37 They suggested that this behavior is caused by the size of the aggregates, which jam and slip between the concentric cylinders gap. If this conjecture is right, it is reasonable to expect that the viscosity values measured during that slip would be smaller and, in fact, such a fall is observed. GABS

Ti = 80 ºC CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa . g= 200 1/s

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Viscosity [Pa s]

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Emulsion W/O with 5% of NaCl Geometry : Concentric cylinders

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Figure 9: Viscosity over time for different water volume fractions at a fixed shear rate: a close on the induction time. Emulsions with 5 % of NaCl at 6 MPa and 4 o C.

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GABS

Emulsion W/O with 5% of NaCl Geometry : Concentric cylinders . g= 200 1/s

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Viscosity [Pa s]

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Figure 10: Viscosity over time for different water fractions at a fixed shear rate: the complete test. Emulsions with 5 % of NaCl at 6 MPa and 4 o C. In the next three figures the effect of shear rate on induction time is shown. Figure 11 evidences that the induction time increases with a decreasing shear rate. For γ˙ = 200 s−1 the jump of viscosity takes place rapidly, just 20 minutes after the final temperature of 4 o C is reached (blue triangles). On the other hand, it takes more than two hours to occur when the shear rate is 100 s−1 (green crosses). Such effect is expected, since the contact area between the two fluids (water and liquid CO2 droplets) increases with the shear rate. Hence, the hydrate formation is facilitated by a higher shear rate. After hydrate formation, the viscosity is also influenced by the increase in shear rate. Probably, the high

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shear rates are responsible for the breaking up of hydrate aggregation. GABS

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10-2

20 30% W/O Emulsion Geometry : Concentric cylinders

10-3

Temperature [°C]A

10

10

80

Ti = 80 ºC CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa

0

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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8

10

12

10 0

14

Time [h] .

H34 - g= 100 1/s .

H33 - g= 150 1/s

.

H32 - g= 200 1/s Temperature °C

Figure 11: Viscosity over time for different shear rates at a fixed water fraction: a close on the induction time. The labels H32, H33 and H34 correspond to different samples. The complete tests showing the effect of shear rate on induction time are shown in Fig. 12. It can be noted that the viscosity reaches an asymptotic value after 22 h of test. The asymptotic viscosity η∞ falls with γ, ˙ what shows that the gas hydrates in crude oil has a shear-thinning behavior. In fact, some tests were carried out for longer periods of time, in order to certify that the level of viscosity was really asymptotic, as in the case displayed in Fig. 13, which shows a test carried out for 72 h with γ˙ = 150 s−1 . Figure 14 depicts a quite practical result, which illustrates how the presence of salt 18


Page 19 of 32

GABS

100 90

100

70 60

10-1 Ti = 80 ºC CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa

50 40 30

10-2


Temperature [°C]A

80

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

20 10

10-3

4

6

8

0

10 12 14 16 18 20 22 24 26

Time [h] .

.

H34 - g= 100 1/s

H32 - g= 200 1/s Temperature °C

.

H33 - g= 150 1/s

Figure 12: Viscosity over time for different shear rates at a fixed water fraction: the complete test. The labels H32, H33 and H34 correspond to different samples. prevents the hydrate formation. Two levels of water fraction emulsions were tested and the experiments were carried out with the shear rate fixed at 200 s−1 . For the solutions with 30 % of water in oil (purple squares and green crosses), η∞ changed from 0.07 Pa.s, in the emulsion with 5 % of salt (purple squares), to 0.4 Pa.s, in the absence of it (green crosses). The asymptotic viscosity increased almost 6 times. Such increase was even more pronounced in the emulsions with 20 % of water (brown circles and blue triangles), in which η∞ raised from 0.025 Pa.s (emulsion with salt) to 0.25 Pa.s (emulsion without salt), an order of magnitude. Hence, it seems that salt is a very effective hydrate inhibitor. The induction

19


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Figure 13: Viscosity over time during three days of test. The shear rate, pressure and temperature after the cooling, remaining constant through the experiment. time was also affected with the presence of salt. 5 % of salt delayed the hydrate formation in approximately 1 h for the emulsion with 20 % of water. However, the delay was larger in the absence of salt in the emulsion with 30 % of water. For this emulsion we observed two viscosity jumps. The first one occurred almost at the same time that in the salty emulsion, but the second was around 2 h later. The effect of salt on the induction time deserves further study but, in general, the salt delays the beginning of hydrate formation because it reduces the driving forces for hydrate formation. We also tried to compare emulsions with larger water fractions, with and without salt. Figure 15 shows an attempt to measure η∞ for an emulsion with 40 % of water in oil, but the jump of viscosity was too high and the rheometer employed was blocked. When this 20


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GABS

10-1


T = 4 ºC

10

AA

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

-2

H17 - Emulsion 30% with 5% of NaCl H26 - Emulsion 30% without NaCl H18 - Emulsion 20% with 5% of NaCl H39 - Emulsion 20% without NaCl

10-3

2 4 6 8 10 12 14 16 18 20 22 24 26 28

Time [h] Figure 14: Viscosity over time for emulsions with 20 % and 30 % of water with and without salt. happens, a block of hydrate (as illustrated in Fig. 15) forms in the lower and upper spaces between the cup-and-bob geometry. The viscosity reached a value of approximately 3 Pa.s, which is more than 15 times the one with 5 % of salt (see the red triangles in Fig. 10). The data measured after hydrate formation were discarded, since the hydrate that was formed blocked the rotor movement and the external magnet kept rotating alone. The data shown in Fig. 16 is conceived to capture the ability of the reconstruction of CO2 hydrates in crude oils. The tests were conducted for two water fractions with the shear rate fixed at 200 s−1 . A sequence of tests were carried out for each emulsion. After the end of the standard test, in which the viscosity was evaluated at fixed pressure and shear rate until its steady state, the emulsion, now with gas hydrates, was left at rest for a period of 21


Energy & Fuels

GABS GABS Exceeded measurement torque

2

1

0

200

400

Discarded values

AA

GABS

10-1

Viscosity [Pa s]

3

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 32

600

Time [s]

10

-2

Geometry : Concentric cylinders H28 - Emulsion 40% without NaCl

10-3

2

4

6

8


10

12

Time [h] Figure 15: Viscosity over time for 40 % water fraction emulsion with absence of salt. The necessary torque to keep the shear rate fixed is above the upper limit of the equipment: the rotor was blocked. In the upper left insertion, the local viscosity evolution and a picture of the material at this state. time. For the emulsion with 30 % of water, the asymptotic viscosity was between 0.4 and 0.5 Pa.s. In the sequence, the emulsion rested for 2 h before the test restarted at the same shear rate and we saw, at the beginning, a peak of viscosity close to 0.6 Pa.s, before it reached the same asymptotic value. In the next step, the emulsion rested 4 h. The peak of viscosity became more pronounced, above 0.7 Pa.s, and, again, after a time long enough, the same final value of viscosity was reached. Finally, the emulsion was left for 8 h before the restart of the test and the reconstruction of hydrates was so intense that the rotor was blocked. The peak of viscosity was above 3 Pa.s. This is a clear time-dependent behavior. As the mechanical forces are brought to end, the inter-crystals forces work in the sense to build up 22


Page 23 of 32

the gas hydrates structure. The same process was observed in the emulsion with 20 % of water in oil, but with a smaller intensity. For such an emulsion, the rotor was not blocked after 8 h at rest. The reconstruction ability of the CO2 hydrates seems to be dramatic and deserves more attention from the flow assurance perspective. GABS

100


Exceeded measurement torque

30% W/O Emulsion

AA

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

20% W/O Emulsion

10-1

8 12 16 20 24 28 32 36 40 44 48 52

Time [h] Initial test without resting time After 2 h of resting time

After 4 h of resting time After 8 h of resting time

Figure 16: Viscosity over time at a fixed shear rate of γ˙ = 200 s−1 and for two water volume fractions 30 % and 20 % w/o. After a initial test, the material is kept at rest for different resting times. A controversial phenomenon related to gas hydrates is the so called memory effect. Supposedly, once the gas hydrates is triggered by a cooling process under high pressure, for example, and them the emulsion is heated, some crystals remain and they will work as a catalyst if a subsequent cooling process is imposed. Hence, under the hypothesis of the 23


Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

existence of memory effects, the induction time should be reduced. Figure 17 is intended to capture a possible memory effect of CO2 hydrates. The test consists of two cycles of heating and cooling. The sample was firstly heated up to 80 o C and cooled to the test temperature of 4 o C. At the end of the first cycle, when η∞ ≈ 0.4 Pa.s, the sample was heated again up to 80 o

C and cooled down to 4 o C. It is worth noting that the induction time was premature at the

second cycle. At the first cycle, the viscosity at 4 o C, η4o C was 0.009 Pas, but at the second cycle η4o C = 0.033 Pas, i.e. 3.67 times the former value. Hence, it seems that the hydrate formation was, in fact, premature, but, in addition, the asymptotic viscosity at the end of the second cycle was much larger, η∞ ≈ 1 Pa.s. This test was conducted under constant pressure by keeping the valve opened during the experiment. Moreover, CO2 was injected into the sample to keep the pressure constant, since gas is consumed when the hydrate is formed. Thus, the amount of gas was larger at the second cycle and this can be the reason for the increase of the amount of hydrates. In order to verify if the larger amount of gas is playing a role at the second cycle in Fig. 17, we conducted some tests with the valve closed. The first test is displayed in Fig. 18. The sample is saturated with gas at the fixed pressure of 6 MPa and 80 o C temperature. As in the previous tests, cooling begins after 8 h, at a constant rate of 0.6 o C/min. When the temperature reaches 4 o C, the valve is closed. Hence, the hydrates starts to form at a pressure of 6 MPa, which decreases abruptly at the beginning of the process and tends to an asymptotic value after a long enough time. We see in Fig. 19 that the peaks of viscosity at the beginning and their asymptotic values are not very different from the cases in which the valve was opened, what suggests that the complement of gas during the process, to keep the pressure constant, is not so important. In other words, it seems that the difference in the amount of gas between the two tests is not relevant in terms of the final amount of hydrates. Finally, we conducted a sequence of four heating and cooling cycles with the valve closed, which are displayed in Fig. 20. The first cycle was conducted in exactly the same way as the other tests, where the maximum imposed temperature was 80 o C. After achieving the working

24


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Page 25 of 32

GABS

40

30 Ti = 40 ºC CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa

-1

10

h 4°C= 0.033

20

.

g= 200 1/s -2

10

10-3

h 9°C= 0.013

h 4°C= 0.009

5

h 18°C= 0.005

10 15 20 25 30 35 40 45 50 55

Temperature [°C]A

100

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

10

0

Time [h] 30% W/O Emulsion Geometry : Concentric cylinders

Viscosity Temperature AA

Figure 17: Viscosity over time for a fixed shear rate and abrupt changes in the temperature history from a higher level of T = 40 o C to a lower level of 4 o C . temperature of 4 o C, the valve was closed. In the second cycle, the maximum temperature was reduced to 40 o C and, after that, to 20 o C, in the third cycle. Interestingly, the three first cycles were quite similar in terms of the peak and final value of viscosity and pressure level. In the fourth cycle, when the sample was heated up again to 80 o C, the increase in the peak of viscosity was dramatic. It was close to 2 Pa.s, 5 times the viscosity of previous cycles. Although more analysis is required, it is possible that the hydrate formation was favored by the heating temperature which induced a higher pressure level than the corresponding one 25


Energy & Fuels

GABS

7

90 80

10-1

6 Ti = 80 ºC CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 .

g= 200 1/s

10-2

5

60 50 40 30

Temperature [ºC]A

70


Pressure [MPa]A

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 32

20

Closed valve after ramp temperature

10 -3

10

4

6

8

4

10 12 14 16 18 20 22 24

0

Time [h] Viscosity

Pressure

Temperature

Figure 18: Viscosity over time. The material is cooled from Ti = 80 o C until Tf = 4 o C. When the final temperature is achieved, the valve is closed and the pressure begins to decay as a sign of hydrate formation. in the first cycle. Although the increase of pressure would lead to a higher level of hydrate formation, we would expect a decrease in the final level of pressure when the temperature of 4 o C was achieved. This phenomenon deserves a deeper investigation.

Conclusions In the present work, we analyzed the rheology of CO2 hydrates slurries by means of a rheometric geometry in a rotational rheometer. The thermodynamic conditions (pressure and temperature) employed to form the hydrates are similar to that used in the oil industry. 26


Page 27 of 32

10

0

GABS

90 80

10

-1

60 50 40

CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa . g= 200 1/s

10-2

30


10-3

4

6

8

Temperature [°C]A

70

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

20 10 0

10 12 14 16 18 20 22 24 26

Time [h] H32 - Opened valve H32 - Temperature 80 °C

H36 - Opened valve H36 - Temperature 40 °C

H42 Closed valve H42 - Temperature 80 °C

Figure 19: Viscosity over time. Comparison between different initial temperatures and between opened and closed valve. The shear rate and the cooling rate are fixed. Before executing the main tests of hydrate analysis, preliminary experiments were realized with the objective to verify the accuracy of the pressure cell. This step is very important since such kind of apparatus is not widely used and the absence of a mechanical contact between the measuring device and the rotor imposes an extra challenge. The main results show the behavior of the viscosity of the samples as a function of the experimental time. The viscosity increases abruptly when the hydrate is formed and subsequently begins to decrease due to the breakdown of the structures. In fact, increasing water fraction and shear rate

27


Energy & Fuels

GABS

80

100

70 60 50

-1

10

40 CR = 0.6 °C/min Tf = 4 ºC Gas = CO2 Pg = 6 MPa . g= 200 1/s

-2

10

Closed valve

10-3

30

30

20

Pressure [Mpa]A

Closed valve after first ramp of temperature Geometry : Concentric cylinders

Temperature [°C]A

30% W/O Emulsion

Viscosity [Pa s]

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 32

20 10

10 0

8 16 24 32 40 48 56 64 72 80 88 96 104

Time [h] Viscosity

Temperature

Pressure

Figure 20: Viscosity over time at a fixed shear rate. When the final temperature is achieved after the first cooling ramp, the valve is closed to keep the amount of gas constant throughout the test. Different melting temperatures are analyzed to evaluate the memory effect of hydrates. favors the hydrate formation. The induction time takes place earlier and the amount of the formed hydrates increases with that quantities. Some of the reported behaviors were also observed by other authors using methane as guest molecule. It is worth noting the building up ability of the CO2 hydrates. After the end of the standard test, the sample with 30 % of water that rested for 8 h blocked the rotor, which was set with γ˙ =200 1/s. This is a typical behavior of time-dependent materials. Overall, this investigation display an experimental data of hydrate rheology using high concentrations of CO2 molecules as the encountered in

28


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Energy & Fuels

the Brazilian pre-salt oil wells.

Acknowledgements This research was partially funded by grants from CNPq (Conselho Nacional de Pesquisa e Desenvolvimento) and PETROBRAS.

29


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References (1) Sloan, E. D. Nature 2003, 426, 353–363. (2) Sum, A. K.; Koh, C. A.; Sloan, E. D. Industrial & Engineering Chemistry Research 2009, 48, 7457–7465. (3) Camargo, R.; Gonçalves, M.; Montesanti, J.; Cardoso, C.; Minami, A perspective view of flow assurance in deepwater fields in Brazil. Offshore Technology Conference. 2004. (4) Tariq, M.; Rooney, D.; Othman, E.; Aparicio, S.; Atilhan, M.; Khraisheh, M. Industrial & Engineering Chemistry Research 2014, 53, 17855–17868. (5) Raman, A. K. Y.; Koteeswaran, S.; Venkataramani, D.; Clark, P.; Bhagwat, S.; Aichele, C. P. Fuel 2016, 179, 141–149. (6) Leopércio, B. C.; de Souza Mendes, P. R.; Fuller, G. G. Langmuir 2016, 32, 4203–4209. (7) Ahuja, A.; Zylyftari, G.; Morris, J. F. Journal of Non-Newtonian Fluid Mechanics 2015, 220, 116–125. (8) Wu, R.; Aman, Z. M.; May, E. F.; Kozielski, K. A.; Hartley, P. G.; Maeda, N.; Sum, A. K. Energy & Fuels 2014, 28, 3632–3637. (9) Zylyftari, G.; Ahuja, A.; Morris, J. F. Chemical Engineering Science 2014, 116, 497– 507. (10) Peixinho, J.; Karanjkar, P. U.; Lee, J. W.; Morris, J. F. Langmuir 2010, 26, 11699– 11704. (11) Di Lorenzo, M.; Seo, Y.; Soto, G. S. Korea 2011, 6, 2–2. (12) Sinquin, A.; Palermo, T.; Peysson, Y. Oil & gas science and technology 2004, 59, 41–57.

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(13) Andersson, V.; Gudmundsson, J. S. Annals of the New York Academy of Sciences 2000, 912, 322–329. (14) Camargo, R.; Palermo, T.; Sinquin, A.; Glenat, P. Annals of the New York Academy of Sciences 2000, 912, 906–916. (15) Rensing, P. J.; Liberatore, M. W.; Koh, C. A.; Sloan, E. D. 2008, (16) Rensing, P. J.; Liberatore, M. W.; Sum, A. K.; Koh, C. A.; Sloan, E. D. Journal of Non-Newtonian Fluid Mechanics 2011, 166, 859–866. (17) Webb, E. B.; Rensing, P. J.; Koh, C. A.; Sloan, E. D.; Sum, A. K.; Liberatore, M. W. Energy & fuels 2012, 26, 3504–3509. (18) Webb, E. B.; Koh, C. A.; Liberatore, M. W. Langmuir 2013, 29, 10997–11004. (19) Webb, E. B.; Koh, C. A.; Liberatore, M. W. Industrial & Engineering Chemistry Research 2014, 53, 6998–7007. (20) Shi, B.-H.; Chai, S.; Wang, L.-Y.; Lv, X.; Liu, H.-S.; Wu, H.-H.; Wang, W.; Yu, D.; Gong, J. Fuel 2016, 185, 323–338. (21) Chapoy, A.; Burgass, R.; Tohidi, B.; Alsiyabi, I. Journal of Chemical & Engineering Data 2014, 60, 447–453. (22) Bozzo, A. T.; Hsiao-Sheng, C.; Kass, J. R.; Barduhn, A. J. Desalination 1975, 16, 303–320. (23) Fingas, M. F. Journal of Petroleum Science Research 2014, 3, 38–49. (24) Teng, H.; Kinoshita, C.; Masutani, S. Chemical Engineering Science 1995, 50, 559–564. (25) Delahaye, A.; Fournaison, L.; Marinhas, S.; Martínez, M. C. Chemical engineering science 2008, 63, 3551–3559.

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(26) Delahaye, A.; Fournaison, L.; Jerbi, S.; Mayoufi, N. Industrial & Engineering Chemistry Research 2011, 50, 8344–8353. (27) Jerbi, S.; Delahaye, A.; Oignet, J.; Fournaison, L.; Haberschill, P. International Journal of Refrigeration 2013, 36, 1294–1301. (28) Oignet, J.; Delahaye, A.; Torré, J.-P.; Dicharry, C.; Hoang, H. M.; Clain, P.; Osswald, V.; Youssef, Z.; Fournaison, L. Chemical Engineering Science 2017, 158, 294– 303. (29) Darbouret, M.; Cournil, M.; Herri, J.-M. International Journal of Refrigeration 2005, 28, 663–671. (30) Saji, A.; Yoshida, H.; Sakai, M.; Tanii, T.; Kamata, T.; Kitamura, H. Energy Conversion and Management 1992, 33, 643–649. (31) Qanbari, F.; Pooladi-Darvish, M.; Tabatabaie, S. H.; Gerami, S. Journal of Natural Gas Science and Engineering 2012, 8, 139–149. (32) Kim, E.; Lee, S.; Lee, J. D.; Seo, Y. Fuel 2016, 164, 237–244. (33) Song, Y.; Wang, F.; Liu, G.; Luo, S.; Guo, R. Fuel 2017, 203, 145–151. (34) Tarcha, B.; Fortes, B.; Soares, E.; Thompson, R. Rheologica Acta 2015, 54, 479–499. (35) Soares, E. J.; Thompson, R. L.; Machado, A. Appl. Rheol. 2013, 23, 62798–1–62798–11. (36) Sloan, E. D.; Koh, C. Clathrate hydrates of natural gases; CRC press, 2008. (37) Webb, E. B.; Rensing, P. J.; Koh, C. A.; Dendy Sloan, E.; Sum, A. K.; Liberatore, M. W. Review of Scientific Instruments 2012, 83, 015106.

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Analysis of CO2 Hydrates in Crude Oils from a

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