in-Water Emulsions - American Chemical Society

Jul 13, 2014 - Engineering Technology Research Institute, CNPC Bohai Drilling Engineering Co., Ltd., Tianjin Tanggu 300457, China. ∥. Department of ...
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Replacement of Methane from Hydrates in Porous Sediments with CO2‑in-Water Emulsions Qing Yuan,†,‡,§ Xiao-Hui Wang,†,§ Abhijit Dandekar,∥ Chang-Yu Sun,†,* Qing-Ping Li,⊥ Zheng-Wei Ma,† Bei Liu,† and Guang-Jin Chen*,† †

State Key Laboratory of Heavy Oil Processing, China University of Petroleum, Beijing, 102249, China Engineering Technology Research Institute, CNPC Bohai Drilling Engineering Co., Ltd., Tianjin Tanggu 300457, China ∥ Department of Petroleum Engineering, University of Alaska Fairbanks, Fairbanks, Alaska, United States ⊥ CNOOC Research Center, Beijing, 100027, China ‡

S Supporting Information *

ABSTRACT: CO2-in-water emulsions formed from polyoxyethylene sorbitan monooleate (Tween 80) and sodium dodecyl sulfate (SDS) were evaluated in terms of stabilization time and emulsion droplet distribution. A CO2 emulsion with 0.5 wt % SDS + 5 wt % Tween 80 was found to be more stable than the other emulsions. With an increase in the stirring rate or pressure or a decrease in the temperature, the size of CO2 emulsion droplets tended to be smaller, and the stabilization time of the CO2 emulsion increased. With the optimized CO2 emulsion, the CH4−CO2 replacement reaction in a hydrate-bearing quartz sand sample was performed in a three-dimensional reactor. In the emulsions, the function of Tween 80 is to make the emulsion much more hydrophilic and reduce the flow resistance of the emulsion, whereas that of SDS is to make the newly formed hydrate particles/layers more granular and looser. The results indicate that, for hydrate reservoirs located in the stability fields of both CO2 hydrate and methane hydrate, the replacement efficiency of the CO2 emulsion can reach 47.8%, higher than those of liquid CO2 and gaseous CO2. The addition of 3.35 wt % salt to the emulsion can prevent the pore spaces of sediments from being blocked.

1. INTRODUCTION Energy and the environment are two key issues that developed and developing nations are confronting in the quest for clean, affordable, and reliable energy. The exploitation of natural gas hydrates (NGHs) has attracted much attention because of their enormous potential for organic carbon storage. Experimental simulations of gas production from methane hydrates in porous media have been widely reported.1−9 However, NGHs play an important role in stabilizing the layers in which they exist.10 The exploitation of NGHs using traditional methods might make these layers unstable, thereby leading to geological disasters, such as earthquakes and submarine landslides.11 Another important issue is the increase of flue gas emissions as a result of the burning of fossil fuels, which plays a major role in the greenhouse effect and global climate change.12 It has been reported that the temperature of the world could increase by 2−5 K in the next century.13 To address these two issues, Hirohama et al.14 and Ohgaki et al.15 proposed a method for hydrate exploitation through the use of CO2, which combines CO2 storage with NGH exploitation. Not only can this approach avoid some of the disadvantages of the traditional proposed exploitation methods, such as the re-formation of hydrate by depressurization, the low heat efficiency of thermal stimulation, and the high cost and potential damage to the layer upon inhibitor addition, but it also provides a means of storing CO2 for an extended period of time.15,16 In addition, the method of CO2 replacement can maintain the stiffness in the granular medium.17 With careful design of the operating conditions, it is possible to replace methane from methane © 2014 American Chemical Society

hydrate with CO2 in the solid phase while maintaining geological stability.18 On the basis of previous studies, Zhao et al.16 and Komatsu et al.19 comprehensively analyzed the thermodynamic and kinetic feasibility of CH4−CO2 replacement. Although the replacement method is regarded as a promising method for exploiting NGHs, the replacement rate generally becomes extremely low after the early stages of the reaction.20,21 Uchida et al.22 found that the induction time of the CH4−CO2 gas replacement reaction can reach several days. Lee et al.23 and Yoon et al.24 inferred that it is the CO2 hydrate formed at the surface of the CH4 hydrate that hinders hydrate decomposition, thereby leading to the decrease in the replacement rate and the final cessation of the replacement reaction. In investigating the replacement mechanism of CH4 hydrate by CO2 molecules using molecular dynamics simulations, Bai et al.25 found that the formation of an amorphous layer of CO2 hydrate provides a significant barrier to the mass transfer of the guest CH4 and CO2 molecules. In addition, the replacement method using gaseous CO2 is also limited by the type of hydrate reservoir. Yuan et al.26 found that the replacement reaction by gaseous CO2 is suitable only for hydrate reservoirs with underlying free gas, high saturation of free gas, or low saturation of water. Received: Revised: Accepted: Published: 12476

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composed of 20−40-mesh quartz sand with an average diameter of 0.38 mm. AR-grade Tween 80 and SDS were supplied by Sigma-Aldrich Company and Beijing Modern Eastern Fine Chemical Company, respectively. 2.2. Emulsion Stabilization Evaluation. A sapphire transparent cell and a high-pressure online particle analyzer were used to evaluate the morphology and stabilization of the C/W emulsions. For a detailed description of the sapphire transparent cell, please refer to our previous articles.34−36 The apparatus used in this work consisted of an air bath, a sapphire cell, and a temperature−pressure detection system. The effective volume of the sapphire cell was 60 mL, and the maximum operating pressure of the cell was 20 MPa. The temperature accuracy of the air bath was ±0.1 K. The morphology and stabilization of the C/W emulsions were examined directly in the sapphire cell. To determine the droplet distributions of the C/W emulsions, a high-pressure online particle analyzer was used; a detailed description of this method can be found in refs 37 and 38. The apparatus consisted of a stainless steel reactor with an effective internal volume of approximately 534 mL and a maximum operating pressure of 30 MPa, where a focused-beam reflectance measurement (FBRM) D600X probe made by Mettler-Toledo Lasentec was installed to perform online detection of the size distribution of the emulsion droplets under the experimental conditions. The experimental procedures for evaluating the morphology and stabilization of the C/W emulsions using the above two apparatuses were as follows: First, certain amounts of SDS and Tween 80, with or without Na2SO4, were added to distilled water and completely dissolved in the distilled water by stirring adequately. After the solution had been placed in the sapphire cell or the particle analyzer, the constant-temperature bath was applied, and the temperature was set to 273.2 K. When the temperature became stable, gaseous CO2 from a CO2 cylinder at ambient temperature flowed into the cell or the particle analyzer and liquefied therein under the low-temperature environment. The injection of CO2 was continued until CO2 could no longer flow into the vessel anymore, and the volume ratio of liquid CO2 to water was measured. The temperature of the bath and the pressure of the emulsion were then adjusted to the specified values. Meanwhile, the stirrer was started, and this time was recorded as the beginning time of emulsion formation. Stirring was continued for 3 h and then stopped. The morphology and stabilization of the emulsion were visually examined, and the time when a water layer started to appear in the bottom of the sapphire cell after the stirrer had been shut down was regarded as the CO2 emulsion stability time. Meanwhile, through the high-pressure online particle analyzer, the distribution and variation of emulsion droplets with time were measured with the FBRM probe. 2.3. Replacement Device and Procedures. The experimental device used for the replacement of CH4 from the gas hydrate by CO2 emulsion mainly consisted of two parts: the emulsion formation part and the hydrate exploitation part. A schematic diagram of the experimental device is shown in Figure S1 (Supporting Information). The emulsion formation part consisted of a high-pressure autoclave, a hand pump, a temperature detector, and a pressure gauge. The autoclave was made of stainless steel and had an effective height of 270 mm and an inner diameter of 103 mm; the maximum operating pressure of the autoclave was 50 MPa. A paddle agitator was used to stir the fluid in the autoclave; its stirring rate could be

The low replacement rate and low replacement efficiency restrict the use of the CO2 replacement method in commercial applications.15 Some researchers have attempted to use liquid CO2 or CO2 emulsions to improve the replacement efficiency. Ota and co-workers20,21,27 studied methane recovery from methane hydrate using pressurized CO2. They found that CH4 hydrate decomposition is most likely dominated by the rearrangement of water molecules in the hydrate, whereas CO2 hydrate formation seems to be dominated by the gas diffusion in the hydrate phase. Yuan et al.28 studied methane recovery from natural gas hydrate in a porous sediment using liquid CO2 in a three-dimensional reactor and found that the replacement reaction could occur even when the conditions remained in the stable zone of methane hydrate. Compared with the method of injecting gaseous CO2, they found that the injection of liquid CO2 is also beneficial for the recovery of CH4 from hydrate reservoirs with either a large amount of free water or without underlying free gas. In addition, McGrail et al.29 used a CO2-in-water (C/W) emulsion to replace methane from CH4 hydrate. Zhou et al.30 found that the use of a CO2 emulsion is superior to the use of liquid CO2 in replacing CH4 from its hydrate because of the excellent diffusion properties of emulsions. Phale et al.31 also found that the injection of a CO2 microemulsion produces a considerably higher amount of methane than the injection of hot water alone. Although better replacement efficiency was obtained for CO2 emulsions than for gaseous and liquid CO2, this result was mainly attributed to the higher replacement temperature and the improved conductivity and diffusivity of CO2 emulsions. From an analysis of the mechanism of CO2−CH4 replacement, the permeation of molecules was found to occur in the hydrate layer. The diffusion of CH4 molecules from the hydrate surface to the gas phase and the diffusion of CO2 molecules from the gas phase to the deeper hydrate-bearing layer are the controlling steps that limit the replacement rate.23,26,32 When methane hydrate is packed by the newly formed hydrate, the replacement reaction becomes slower or even ceases. However, in general, the previous studies on the replacement of CO2 emulsions did not focus on increasing the replacement rate by improving the control step. In this work, a new C/W emulsion was formed using sodium dodecyl sulfate (SDS) and polyoxyethylene sorbitan monooleate (Tween 80) as emulsifying agents. Tween 80 is inexpensive, nontoxic, and widely used in the food and medical fields, and SDS is an anionic surfactant that is widely used in the gas hydrate field. The function of Tween 80 is to make the emulsion much more hydrophilic and reduce the flow resistance of the emulsion, whereas that of SDS is to make the newly formed hydrate particles/layers more granular and looser.33 The stability of the proposed emulsifying agent was studied, and the replacement effect of CH4 from its hydrate in porous media with this type of CO2 emulsion was evaluated in a three-dimensional reactor. The replacement rate and replacement efficiency were found to be fundamentally improved through an increase in the permeabilities of CO2 and CH4 in the loose hydrate layer.

2. EXPERIMENTAL SECTION 2.1. Materials. The methane and carbon dioxide used in this work were supplied by the Beijing Beifen Gas Industry Corporation, with purities of 99.9% and 99.5%, respectively. Brine was prepared in our laboratory with sodium sulfate (Na2SO4) supplied by Beijing Modern Eastern Fine Chemical Company. The sediment used in the experiments was 12477

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Table 1. Experimental Conditions for Investigating Emulsion Stability with the Sapphire Cell run

temperature (K)

pressure (MPa)

Tween 80 (wt %)

SDS (wt %)

CO2/H2O (v/v)

salt concentration (wt %)

1 2 3 4 5

293.2 293.2 293.2 293.2 293.2

12 12 12 12 12

5 5 5 5 5

0 0.1 0.5 0.5 0.5

2:1 2:1 2:1 2:1 2:1

0 0 0 3.35 5

Table 2. Experimental Conditions for Investigating the Distribution of Emulsion Particles with the High-Pressure Online Droplet Analyzer run

temperature (K)

pressure (MPa)

Tween 80 (wt %)

SDS (wt %)

CO2/H2O (v/v)

stirring rate (rpm)

salt concentration (wt %)

6 7 8 9

288.2 288.2 298.2 288.2

12 12 12 8

5 5 5 5

0.5 0.5 0.5 0.5

3.5:1 3.5:1 3.5:1 3.5:1

800 1200 1200 1200

0 0 0 0

system was adjusted to the specified hydrate reservoir temperature, and valve 12 was opened, water was injected into the space above the piston by the hand pump, and the CO2 emulsion in the mixing tank was injected into the hydrate reservoir through the movement of the piston until the gas space in the reactor was fully filled with the emulsion. After the emulsion injection stage, the CH4−CO2 replacement reaction started. The composition of the fluid in the top of the reactor was analyzed by gas chromatography (GC) every 24 h. The replacement reaction was assumed to be completed when the fluid composition did not change within 24 h. Next, the gas in the reactor was released. The release process was divided into two steps: In the first step, the gas was released slowly from the reactor until the pressure in the reactor was 0.5 MPa higher than the hydrate equilibrium pressure under the current conditions, and the released gas was collected by a cylinder. The gas compositions in the reactor and cylinder in this step were analyzed by GC. The corresponding numbers of moles of CH4 and CO2 in the reactor and in the gas cylinder collected in 1 1 this step are denoted as nCH , nCO , n1CH4,cylinder, and 4,reactor 2,reactor 1 nCO2,cylinder. In the second step, the temperature of the water bath was adjusted to 293.2 K. Hydrate could dissociate thoroughly, and the dissociated gas was released from the reactor and collected by another cylinder. The gas compositions in the reactor and cylinder in this step were also analyzed by GC. The corresponding numbers of moles of CH4 and CO2 in the reactor and in the gas cylinder collected in the second 2 2 2 , nCO , nCH , and step are denoted as nCH 4,reactor 2,reactor 4,cylinder 2 nCO2,cylinder.

adjusted from 0 to 1300 rpm. A piston was installed in the autoclave and was located at the top of the autoclave at the beginning of the experiment; and the CO2 emulsion is formed in the space under the piston. The temperature of the autoclave was maintained by a water bath with an accuracy of ±0.05 K. A detailed description of the hydrate exploitation part of the device can be found in our previous work.5,7,26,39 The hydrate exploitation part consisted of a high-pressure reactor, a cooling system, a gas collection system, and a data acquisition system. The reactor was 300 mm in internal diameter and 100 mm in height, with a volume of approximately 7 L and a maximum operating pressure of 16 MPa. Sixteen thermocouples, divided into four groups, were inserted in the reactor to detect the temperature distribution and variation during the hydrate formation and replacement processes. Each group included four thermometers distributed at the same depth but at different distances of 132, 99, 66, and 33 mm from the center of the reactor. The depths of the four groups of thermometers were 82, 58, 34, and 10 mm. The distribution of the thermocouples is shown in Figure S2 (Supporting Information). The experimental process used for CH4−CO2 replacement with CO2 emulsion included four stages: hydrate sample formation, CO2 emulsion formation, emulsion injection, and CH4−CO2 replacement. For a detailed procedure of the hydrate sample formation process, please refer to our previous work.5,7,26,39 The procedure for CO2 emulsion formation was similar to that introduced in section 2.2. After the preparation of the CH4 hydrate sample and the CO2 emulsion, the emulsion injection stage was started. Valves 7, 13, and 17 (or 18) (see Figure S1, Supporting Information) were opened, and then the gas in the replacement reactor was slowly discharged. When the pressure in the reactor (controlled by a back-pressure valve) had decreased to be slightly higher than the equilibrium value for CH4 hydrate under the experimental conditions, valves 9 and 11 were opened, gaseous CO2 was injected into the reactor from the bottom, and CH4 exchanged with CO2 in the pore space of the sediments and then flowed out from the top of the reactor. During this process, the pressure in the reactor was maintained at the equilibrium value of methane hydrate, to help reduce the dissociation of hydrate, and the composition of the gas was measured with an HP7890 gas chromatograph. When the mole percent of CO2 in the released gas exceeded 98%, it was assumed that the CO2−CH4 exchange process in the gas phase was completed, and valves 7, 9, 11, and 13 were closed. Thereafter, the temperature of the cooling

3. RESULTS AND DISCUSSION 3.1. Emulsion Stability Evaluation. Torino et al.40 reported that, for pressures up to 25 MPa and temperatures of 298−333 K, C/W emulsions can be formed with 5 wt % Tween 80 for water concentrations as low as 10 vol %. In this work, Tween 80 was also used to form the CO2 emulsions. To increase the replacement rate, SDS was added to the emulsions to enable the newly formed hydrate to be looser.33,34 It was first needed to evaluate the stability of the CO2 emulsions after addition of SDS. The stabilities of the CO2 emulsions obtained using two different CO2/H2O ratios were then evaluated using the sapphire cell and the high-pressure online droplet analyzer, and the experimental conditions are listed in Tables 1 and 2, respectively. During the emulsion stability evaluations in the 12478

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into the CO2 phase and the sulfate ion remaining in the water phase, which enables droplets with the same charge to exhibit strong repulsion and effectively inhibits the aggregation of droplets. 3.1.2. Effect of Salt on Emulsion Stabilization. To examine the effect of salt on the stabilization of the emulsion, the stabilization times of CO2 emulsions formed with different Na2SO4 concentrations of 0, 3.35, and 5 wt % (runs 3−5, respectively) were investigated at 293.2 K and 12 MPa, where the emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80 and the CO2/H2O volume ratio was 2:1. The experimental results indicate that the stabilization time of the CO2 emulsion decreased with increasing concentration of Na2SO4. For CO2 emulsions without salt, the stabilization time was 180 min, whereas it was only 150 and 90 min for the systems with 3.35 and 5 wt % Na2SO4, respectively. This phenomenon is due to the disruption of the H-bonding of the ethylene oxide groups of Tween 80 with water caused by the salt, thus effectively making the surfactants less hydrophilic.40 In addition, Na2SO4 can inhibit the ionization of SDS and thereby decrease the charge of the droplets. This can also decrease the stabilization of the CO2 emulsion. 3.1.3. Emulsion Droplet Size Distribution. The variation of CO2 emulsion droplet size distribution with time after the stirrer had been stopped is shown in Figure 2 for run 9; the

sapphire cell, the temperature and pressure were set at 293.2 K and 12 MPa, respectively, and the CO2/H2O volume ratio was 2:1 in five groups of experimental runs (runs 1−5). The effects of surfactant concentration, mixing ratio, and salt concentration were investigated. During the emulsion droplet size evaluation in the high-pressure online droplet analyzer, the dosages of Tween 80 and SDS were 5 and 0.5 wt %, respectively, and the CO2/H2O volume ratio was 3.5:1 in four experimental runs (runs 6−9). The effects of temperature, pressure, and stirring rate were investigated in these four runs. For these nine runs, the experimental temperature was varied between 288.2 and 298.2 K to examine the emulsion stability in near-ambient environments. 3.1.1. Effect of Surfactants on Emulsion Stabilization. The stabilization of CO2 emulsions containing only Tween 80 or mixtures of Tween 80 and SDS with different concentration ratios was investigated to examine the influence of SDS on emulsion stabilization. The typical morphologies of the emulsion with 5 wt % Tween 80 at different times after the stirrer had been stopped are shown in Figure 1 for conditions

Figure 1. Morphology variation of the CO2 emulsion with time in run 1 after the stirrer had stopped, where the emulsifying agent was 5 wt % Tween 80 and the CO2/H2O volume ratio was 2:1 at 293.2 K and 12 MPa.

of 293.2 K and 12 MPa. The CO2 emulsion was found to be uniform and milky at the time when the stirrer was stopped. A water layer gradually appeared at the bottom of the sapphire cell with the passage of time, indicating that the emulsion was a C/W emulsion and not a W/C emulsion because the turbidity of the CO2 emulsion at the top of the reactor did not decrease, as would be expected for a W/C emulsion upon the settling of water droplets.40 Furthermore, the research of Torino et al.40 indicated that Tween 80 is easier to dissolve in water than in liquid CO2 when the temperature is below 318.2 K. According to the Bancroft rule, the continuous phase of the emulsion is the one that has the highest solubility of the emulsifier, which also supports the conclusion that the type of emulsion in this work was C/W. The stabilization of the CO2 emulsions can be characterized in terms of the time required for the appearance of layers in the emulsion (see the area denoted by the arrow in Figure 1). The experimental results indicate that the CO2 emulsion formed with 5 wt % Tween 80 stabilized for only 8 min. In fact, the stabilization time of the CO2 emulsion with 0.1 wt % SDS + 5 wt % Tween 80 was found to be no longer than that with only 5 wt % Tween 80. However, when the mass concentration of SDS was increased to 0.5 wt %, the emulsion was stable for at least 180 min, which means that adding a suitable concentration of SDS is beneficial for the stabilization of C/W emulsions. During the emulsion formation process, SDS is adsorbed at the interface of CO2 droplets, with the alkyl group of SDS inserting

Figure 2. Distributions of emulsion particles at different times in run 9 at 288.2 K and 8 MPa, where the emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80, the CO2/H2O volume ratio was 3.5:1, and the stirring rate was 1200 rpm.

experimental conditions were 288.2 K and 8 MPa, the emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80, CO2/H2O volume ratio was 3.5:1, and the stirring rate before stopping was 1200 rpm. As is known, if an emulsion is not stable, the size of the emulsion droplets will move toward a larger chord length, and the distribution curve will become wider. From Figure 2, the distribution of the CO2 emulsion in run 9 was found to vary only slightly with time after the stirrer had stopped, implying the CO2 emulsion remained stable. The distribution of the emulsion particle size was mainly below 10 μm, and the average chord length of the droplets was approximately 5 μm; that is, the C/W emulsion was a microemulsion. The smaller chord length of the droplets also implies that the emulsion was stable. Figure S3 (Supporting Information) shows the size distributions of the droplets of the CO2 emulsions at different times after the stirrer had been stopped for runs 6 and 7. The experimental conditions were 288.2 K and 12 MPa, the 12479

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B (hydrate saturation of 24.36%) and run C (hydrate saturation of 23.00%), the temperature of hydrate reservoir was 275.7 K, corresponding to the stability fields of both CO2 hydrate and methane hydrate. The numbers of moles of CH4 and CO2 in the hydrate after replacement and the total number of moles of CH4 in the hydrate before replacement were calculated according to the equations

emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80, and the CO2/H2O volume ratio was 3.5:1. The stirring rate before stopping was 800 rpm for run 6 (black line) and 1200 rpm for run 7 (red line). The chord length distribution of the emulsion droplets with a stirring rate of 1200 rpm was found to be narrower and higher than that with a stirring rate of 800 rpm. The shear rate in a reactor increases with increasing stirring rate, resulting in smaller emulsion droplets. Similar droplet size distributions were also found at different times after the stirrer had been stopped for both run 6 and run 7. Figure S4 (Supporting Information) shows a comparison of the CO2 emulsion droplet distributions at 288.2 K (run 7) and 298.2 K (run 8) 5 min after the stirrer had been stopped (the stirring rate before stopping was 1200 rpm), where the emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80, the CO2/H2O volume ratio was 3.5:1, and the system pressure was 12 MPa. After the stirrer was stopped, the distribution curve of the CO2 emulsion droplets at 288.2 K was found to be slightly narrower and closer to a smaller chord length than that at 298.2 K. That is, with an increase in the temperature, the droplet size increased, whereas the stability of the emulsion decreased. This is because an increase in the thermal energy leads to a decrease in the H-bonding between the surfactant head groups and water.40 Figure S5 (Supporting Information) shows the distribution curves of the droplets in runs 7 and 9 formed at 8 and 12 MPa, respectively, at different times the stirrer had been stopped, under otherwise identical experimental conditions (the emulsifying agent was 0.5 wt % SDS + 5 wt % Tween 80, the CO2/H2O volume ratio was 3.5:1, and the system temperature was 288.2 K). With the passage of time, the curve for the system at 8 MPa moved to a large chord length much more quickly than that for the system at 12 MPa, and the number of emulsion droplets for the system at 8 MPa was gradually less than that for the system at 12 MPa; that is, the emulsion formed at 12 MPa was more stable than that formed at 8 MPa. Surfactant adsorption increases with increasing pressure, and a larger concentration of surfactant at the interface will increase the stability of the CO2 emulsion.41 As the pressure increases, the density of CO2 also becomes closer to that of water. Consequently, the rate of drainage from the thin film due to gravity is reduced, thereby resulting in a more stable emulsion.41 3.2. CO2 Emulsion Replacement Results. Three groups of experiments, denoted as runs A−C, were conducted in this work to investigate the performance of CO2−CH4 replacement with the CO2 emulsion. The effects of the hydrate reservoir properties and the addition of salt to the emulsion on the replacement reaction were investigated. The experimental conditions of CH4 hydrate formation and CO2 emulsion formation are presented in Tables S1 and S2, respectively (Supporting Information) for the three runs. The concentrations of SDS and Tween 80, the pressure, and the stirring rate in the three runs were the same: 0.5 and 5 wt %, 15 MPa, and 1200 rpm, respectively. The emulsion in run C with a CO2 concentration of 67.8 vol % contained 3.35 wt % Na2SO4 to investigate the effect of salt on the replacement, whereas the other conditions were the same as those in run B. The experimental conditions of the CH4−CO2 replacement reaction are presented in Table S3 (Supporting Information). For run A, with a hydrate saturation of 15.09%, the temperature of the hydrate reservoir was 281.2 K, corresponding to the stability field of CO2 hydrate but not methane hydrate, whereas for run

2 T 1 2 nCH = nCH + nCH + nCH 4,H 4,cylinder 4,cylinder 4,reactor

(1)

1 1 nCH4,R = nCH + nCH 4,cylinder 4,reactor

(2)

2 2 1 nCO2,H = nCO + nCO − nCO 2 ,cylinder 2 ,reactor 2 ,reactor

(3)

nTCH4,H

where is the total number of moles of CH4 in the hydrate before replacement; nCH4,R is the number of moles of CH4 replaced from the hydrate; and nCO2,H is the number of moles of CO2 in the hydrate phase, which is equal to the total number of moles of CO2 in the reactor and gas cylinder obtained in the second gas release process excluded from the number of moles of CO2 in the gas phase of the reactor during the first step of the release process. The numbers of moles of CH4 and CO2 in the cylinders and in the reactor were calculated according to the Patel−Teja equation of state,42 and the mole fraction of the gas phase was determined by GC. The replacement efficiency of CH4 hydrate (η) is defined as the ratio of the number of moles of CH4 replaced from the hydrate to the total number of moles of CH4 hydrate, which was calculated as follows nCH ,R η = T 4 × 100% nCH4,H (4) 3.2.1. Variation of Temperature during CO2 Emulsion Injection. To examine the effect of emulsion injection on the temperature of the hydrate reservoir, the variations in temperature with time during the injections of gaseous CO2 and CO2 emulsion were investigated in this work. Because the temperature variations in runs A−C exhibited similar trends, run B was taken as an example, and the temperature variation during the emulsion injection of run B is shown in Figure S6 (Supporting Information). During the gaseous CO2 injection stage, the temperature in the reactor was initially constant and then increased gradually. This behavior is due to the fact that the initial temperature of gaseous CO2 was higher than that of the hydrate reservoir. During the emulsion injection stage, the emulsion at 290.2 K caused the temperature to increase again. In addition, the temperatures at different sites exhibited similar variations with time, indicating that the emulsion had an improved diffusion capacity in the porous sediment. 3.2.2. Variation of CH4 and CO2 Mole Fractions in the Reactor. Figures 3−5 show the variations with time of the CH4 and CO2 compositions in the liquid phase for runs A−C, respectively. For run A, as shown in Figure 3, the mole fraction of CH4 in the liquid phase reached 18% after 24 h and exhibited little change thereafter. This behavior is a result of the fact that the experimental temperature of the hydrate reservoir was set at 281.2 K during the replacement process, which is located in the stability field of CO2 hydrate but not CH4 hydrate. When the emulsion at 293.2 K was injected into the sediment, the CH4 hydrate dissociated significantly because of the high temperature of the hydrate reservoir, and the total release ratio of run 12480

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Figure 3. Variation of CH4 and CO2 mole fractions in the reactor with time in run A.

Figure 5. Variation of CH4 and CO2 mole fractions in the reactor with time in run C.

A reached 53.55%. The variations of the CH4 and CO2 mole fractions in the reactor for run A were mainly caused by the thermal dissociation of the hydrate, rather than by CO2 replacement. Therefore, the method of CO2 emulsion replacement is not suitable for hydrate reservoirs whose conditions are near the equilibrium curve. In run B, the temperatures of the replacement process and the emulsion were decreased to 275.7 and 290.2 K, respectively, as listed in Tables S2 and S3 (Supporting Information). As shown in Figure 4, CH4−CO2 replacement was successfully

3.2.3. Effect of CO2 Emulsion on the Permeability of Sediment. The high permeability of sediment is beneficial for hydrate exploitation. The effect of the replacement is also proportional to the permeability. If the sediment has a low permeability, it will be difficult to inject a CO2 emulsion into the hydrate reservoir, and the emulsion will not be well distributed in the sediment. Meanwhile, it will also be difficult for the CH4 replaced from the hydrate to diffuse into the gas production well. To investigate the effect of the emulsion on the permeability of sediment, the variation of the top pressure with time during the gas production process was investigated, as shown in Figure 6. For runs A and B, when valve 7 in Figure

Figure 4. Variation of CH4 and CO2 mole fractions in the reactor with time in run B. Figure 6. Variations of pressure with time during gas production for three runs.

S1 (Supporting Information) was opened, the pressure decreased quickly, and when valve 7 was closed, the pressure increased quickly again because of the hydrate dissociation, indicating that the pore channels of the sediment were blocked, because a massive hydrate was formed from the emulsion containing hydrate formation promoter (SDS). The emulsion in run C was formed by adding 0.5 wt % SDS + 5 wt % Tween 80 + 3.35 wt % salt. Figure 6 shows that the pressure in run C decreased gradually with time during gas production, which means that the pore channels were not blocked after the salt had been added to the emulsion and that the gas in the reactor could be constantly discharged from the reactor. The salt changed the equilibrium curve of the hydrate. The chargescreening effect provided by adding salt can also decrease the trend of the formation of the massive hydrate particles and can thus successfully prevent the blockage of pore channels.

realized under these conditions. During the replacement process, the mole fraction of CH4 in the reactor increased, whereas the mole fraction of CO2 decreased. The mole fraction of CH4 in the gas phase was 4.5% at the end of the reaction, indicating a replacement efficiency similar to that of liquid CO2. For run C, the emulsion was formed from liquid CO2 + 0.5 wt % SDS + 5 wt % Tween 80 + 3.35 wt % Na2SO4 solution. Figure 5 shows that the mole fraction of CH4 in the reactor reached 12% after 24 h and continually increased until it reached 20%. In comparison, the replacement effect in run C was better than that in run B, for two reasons: First, CH4 hydrate dissociated quickly because of the Na2SO4 solution added in the emulsion. Second, the Na2SO4 solution was helpful in decreasing the trend of pore blockage, so that CO2 and CH4 permeated in the sediment much more easily. The function of Na2SO4 is further discussed later in this work. 12481

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3.2.4. Gas Production and Replacement Efficiency. The amounts of CH4 from the hydrate replaced with CO2 were 1.623, 2.014, and 2.230 mol for runs A−C, respectively. That is, the number of moles of CH4 from the hydrate replaced in run C was the greatest, whereas that in run A was the lowest. The replacement ratios of runs B and C were 41.27% and 47.8%, respectively. As shown in Figure 3, the CH4 mole fraction in the reactor for run A barely changed with time, indicating that most of the CH4 was from the thermal dissociation of the hydrate and only part of the CH4 was replaced by CO2. In addition, the hydrate saturation in run A was the lowest. In run C, the salt in the emulsion promoted CH4 hydrate dissociation and decreased hydrate particle aggregation, resulting in the best replacement efficiency. Figure 9 shows the replacement efficiencies for CO2 emulsion (run C of this work), liquid CO2,28 and gaseous

To investigate the mechanism by which the emulsion with salt can improve the permeability of the pore space, the temperature variation and distribution of the hydrate droplets formed from emulsions with and without salt were examined using the high-pressure online particle analyzer. Figure 7 shows

Figure 7. Variations of temperature with time during the cooling of emulsions with and without salt.

the variation in temperature during the cooling process of the emulsion for hydrate formation from the CO2 emulsion for an initial emulsion temperature and pressure of 288.9 K and 12 MPa, respectively. The temperature decreased gradually, but an abrupt increase was observed when the hydrate formed. By comparison, the times when the hydrate started to form from the CO2 emulsions with and without salt were the same; however, the temperature of hydrate formation from the CO2 emulsion with salt was lower than that from the CO2 emulsion without salt. The cooling rate of the 3.35 wt % salt solution was higher than that of the pure water system because of the higher specific heat of pure water. Figure 8 shows a comparison of the

Figure 9. Comparison of CH4 hydrate replacement efficiencies with gaseous CO2, liquid CO2, and CO2 emulsion.

CO2.26 The corresponding experimental conditions in this work and in the literature are listed in Table S4 (Supporting Information). The replacement efficiency for the CO2 emulsion reached 47.8%, which is much higher than those reported for gaseous CO2 and liquid CO2. The reason for the good efficiency in run C in this work is three-fold: First, the diffusion of the CO2 emulsion is better than that of liquid CO2, so the CO2 emulsion can cover a larger area and increase the contact area between the CO2 and CH4 hydrate. Second, the Na2SO4 in the emulsion can inhibit hydrate formation and promote CH4 hydrate dissociation, thus preventing the formation of massive hydrate particles. Third, the SDS in the emulsion can make the newly formed hydrate layer looser, which contributes to the mass transfer of CO2 and CH4 in the hydrate layer. 3.2.5. Mechanism of the Promoting Effect of the Emulsion on Replacement. The conceptual mechanism on CH4−CO2 replacement can be divided into four steps:26 (1) diffusion of the CO2 emulsion to the surface of the CH4 hydrate in porous media, (2) dissociation of the CH4 hydrate and escape of CH4 molecules from the hydrate cage, (3) rearrangement of CH4 and CO2 in the hydrate cage; and (4) diffusion of CH4 molecules from the hydrate surface to the gas phase and of CO2 molecules into deeper hydrate-bearing layers. Of these four steps, the fourth is the controlling step in the replacement reaction.23,30 When CH4 hydrate is packed by the newly formed hydrate, the replacement reaction will become slower or cease. However, the study on the promoting effect of emulsions for the replacement in the literature generally focused on the first

Figure 8. Comparison of hydrate particle distributions formed in salt solution and pure water at 7.5 MPa and 276.2 K.

distributions of hydrate particles formed from the CO2 emulsions with and without salt. The curve of the hydrate particle distribution formed from the CO2 emulsion with salt was closer to the smaller chord length than that formed from the CO2 emulsion without salt. The trend of massive hydrate particle formation with salt was smaller, which illustrates that salt in a CO2 emulsion can prevent the blocking of the sediment. This conclusion is consistent with that of Lin et al.34 12482

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Author Contributions

step of the mechanism, aiming to increase the rate by increasing the diffusion of the emulsion in the sediment.30 In this work, the emulsion is formed with liquid CO2 + 3.35 wt % Na2SO4 solution + 0.5 wt % SDS + 5 wt % Tween 80. The function of Tween 80 is to make the emulsion much more hydrophilic and decrease the flow resistance of the emulsion. The function of SDS in the emulsion is to make the newly formed hydrate particles more granular and the newly formed hydrate layer looser. As a result, the permeability of CO2 and CH4 in the hydrate layer increases, and the newly formed hydrate helps keep the layer stable. Figure S7 (Supporting Information) shows the morphologies of CH4 hydrates formed in SDS solution and in distilled water under a microscope. The hydrate layer in SDS solution is thicker and looser than that in distilled water. The loose hydrate layer can improve the permeability of CO2 and dramatically increase the rate of the replacement reaction in the later stage. In addition, as discussed above, salt can be added to decrease the formation of massive hydrate particles that will plug the fluid transfer channels.

§

These authors contributed equally to this work.

Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Financial support received from the National 973 Project of China (No. 2012CB215005) and the National Natural Science Foundation of China (Nos. U1162205 and 51376195) is gratefully acknowledged.

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4. CONCLUSIONS The stability of CO2 emulsions after addition of SDS was evaluated by observing the variations in the morphology of the CO2 emulsion and the chord length distribution of the emulsion droplets. Under the conditions employed, a CO2 emulsion with 0.5 wt % SDS + 5 wt % Tween 80 can stabilize for at least 180 min, which is long enough for the injection operation. A high stirring rate, low temperature, and high pressure are beneficial for the stability of the CO2 emulsion. For hydrate reservoirs located in the stability field of CO2 hydrate but not methane hydrate (run A), a high replacement efficiency is generally expected. However, the experimental results indicated that the injection of CO2 emulsion will quickly induce methane hydrate dissociation, which goes against the purpose of hydrate exploitation with CO2 emulsions. For hydrate reservoirs located in the stability fields of both CO2 hydrate and methane hydrate, the injection of CO2 emulsion formed by 0.5 wt % SDS + 5.0 wt % Tween 80 + 3.35 wt % Na2SO4 provides the best replacement efficiency compared with injecting liquid CO2 or gaseous CO2. CO2 with seawater instead of pure water is more suitable for the replacement of methane from hydrate reservoirs. For the replacement of methane from hydrate reservoirs with CO2-in-water emulsions, the presence of Tween 80 can make the emulsion much more hydrophilic and decrease the flow resistance of the emulsion, the presence of SDS can make the newly formed hydrate particles more granular and the newly formed hydrate layer looser, and the addition of salt can change the equilibrium curve of the hydrate and decrease the formation of massive hydrate particles that plug the fluid transfer channels.

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ASSOCIATED CONTENT

* Supporting Information S

Tables of experimental conditions; figures of apparatus, emulsion particle distribution, variation of temperature, and hydrate morphology. This material is available free of charge via the Internet at http://pubs.acs.org.

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REFERENCES

AUTHOR INFORMATION

Corresponding Authors

*Fax: +86 10 89733156. E-mail: [email protected] (C.Y.S.). *E-mail: [email protected] (G.J.C.). 12483

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