H2O System in the Hydrate

Article pubs.acs.org/jced

Phase Equilibria for the CO2/CH4/N2/H2O System in the Hydrate Region under Conditions Relevant to Storage of CO2 in Depleted Natural Gas Reservoirs Duo Sun,† John Ripmeester,‡ and Peter Englezos*,† †

Department of Chemical and Biological Engineering, University of British Columbia, Vancouver, British Columbia V6T 1Z3, Canada Steacie Institute for Molecular Sciences, National Research Council Canada, Ottawa, Ontario K1A 0R6, Canada

‡

ABSTRACT: The CO2, CO2/CH4, CO2/N2, and CO2/N2/CH4 hydrate equilibria were determined in a stirred high-pressure vessel (autoclave) for temperatures similar to those in depleted natural gas reservoirs in the Alberta portion of the Western Canada Sedimentation basin in Canada. In addition, the equilibrium hydrate formation conditions were also determined by differential scanning calorimetry under a constant pressure of 3200 kPa. Also, experiments with saline water corresponding to 2 and 4 wt % of NaCl solution were used in order to simulate more realistic reservoir conditions. Equilibrium conditions in the autoclave system show a ±40 kPa agreement with the calculated values using CSMGem software. Similarly, the hydrate dissociation temperatures measured with differential scanning calorimetry show ±0.2 K agreement with the calculated values. The increase in salinity was found to shift the equilibrium to less favorable conditions and to decrease the amount of hydrate formed.

1. INTRODUCTION It is well-known that molecules such as CO2, H2, N2, CH4, C2H6, and C3H8 (guest molecules) can be accommodated inside well-defined cages of hydrogen-bonded water molecules (host lattice) to form nonstoichiometric inclusion compounds known as clathrate or gas hydrates.1,2 One of the properties of gas hydrates is that when a mixture of hydrate forming gases forms hydrate crystals the composition of the gases in the hydrate is different from that in the gas and this leads to the possibility of gas separation.3 This concept has been exploited for the development of hydrate-based capture processes. Gas hydrate may form from flue gases (CO2/N2) and fuel gases (CO2/H2) for CO2 post- and precombustion capture, respectively.4−7 Captured CO2 may also be stored in depleted oil and gas reservoirs.8 It is then also possible that the thermodynamic conditions are such that CO2 is stored in whole or in part as a solid gas hydrate, which is advantageous because solid storage reduces the mobility and migration of CO2 in the reservoir.9−12 Depleted oil and gas reservoirs constitute an attractive geological formation because the fluid trapping mechanisms and the reservoir properties are known.13 The Sleipner West gas field in the North Sea and the Otway project in Australia are examples.13,14 The storage potential in the worldwide oil and gas fields is estimated to be 400 Gt of CO2 and 900 Gt of CO2, respectively.15,16 It has been suggested that there are about 120 hydrocarbon reservoirs in the Alberta portion of the Western Canada Sedimentation basin, Canada, suitable for CO2 storage in the gas hydrate state. There is the potential to store about 61 Gt of CO2 in depleted hydrocarbon © XXXX American Chemical Society

reservoirs in Alberta in hydrate form. This paradigm may be also suitable for storage of CO2 in similar subsurface porous formations in other parts of the worlds and thus offers an effective strategy to mitigate climate change.9 Computer simulations considering methane as residual natural gas in the reservoir have shown that by regulating the injection temperature, the injected CO2 does not form hydrate near the wellbore and the amount of CO2 stored exceeds that of CH4 originally in place.10,11 The low pressure or shallow storage process has also been demonstrated at the lab scale and it was shown that the storage capacity increases substantially when CO2 forms hydrate as compared to low pressure gaseous storage.12 Moreover, reservoir salinity was found to decrease the extent of hydrate formation but on the other hand suitable environmentally benign additives exist that may enhance the amount of CO2 stored.17 The presence of residual methane leads to mixed hydrate formation and thus the phase diagram becomes an additional important consideration in the design of the relevant processes.10,11 Moreover, the captured flue gases are not 100% CO2 for economic reasons but also contains N2 and O2. Thus, when one considers the phase equilibria for the system under consideration then one deals with a multicomponent Special Issue: Proceedings of PPEPPD 2016 Received: June 29, 2016 Accepted: September 5, 2016

A

DOI: 10.1021/acs.jced.6b00547 J. Chem. Eng. Data XXXX, XXX, XXX−XXX

Journal of Chemical & Engineering Data

Article

Table 1. Hydrate Equilibrium Pressures Measured in High-Pressure Crystallizer under Fixed Temperaturesa P/kPa in water sample gas or gas mixtures CO2

T/K

this work

CSMGem

this work

CSMGem

this work

CSMGem

1760 1752 1747 2023 1996 1995 2296 2245 2258 1772 1785 1800 2008 2013 2011

1776

1956 1932 1931 2222 2195 2214 2560 2519 2555 1971 1979 1977 2240 2267 2235

1967

2164 2149 2187 2498 2476 2467 2856 2850 2828 2182 2190 2191 2495 2482 2475

2185

278.15

276.15

277.15 #1: (95.10/4.90 mol %) #2: (95.03/4.97 mol %) #3: (94.95/5.05 mol %) 278.15

CO2 (85)/N2 (15)

276.15

277.15 #1: (85.03/14.97 mol %) #2: (84.83/15.17 mol %) #3: (84.94/15.06 mol %) 278.15

CO2 (78)/N2 (16)/CH4 (6)

276.15

277.15 #1: (78.02/15.89/6.09 mol %) #2: (77.98/15.98/6.04 mol %) #3: (77.85/16.06/6.09 mol %) 278.15

a

in 4 wt % NaCl

276.15

277.15

CO2 (95)/CH4 (5)

in 2 wt % NaCl

2288 2268 2271 2080 2092 2083 2350 2359 2363

2009

2278

1792

2024

2290

2071

2346

2675 2664 2668 2140 2149 2151 2430 2409 2383

2666

2740 2744 2711

2727

2128

2405

2557 2522 2518 2308 2301 2315 2619 2625 2576

2231

2540

1980

2241

2545

2295

2609

2955 2943 2985 2342 2316 2351 2664 2698 2682

2977

3037 3010 3064

3035

2352

2667

2839 2852 2821 2564 2577 2543 2921 2940 2912

2487

2838

2194

2491

2843

2553

2913

3327 3309 3317 2589 2636 2617 2971 2964 2939

3343

3389 3410 3421

3391

2608

2968

Standard uncertainties u are u(T) = 0.1 K and u(P) = 0.075%.

sand was obtained from Sigma-Aldrich with a porosity of 0.35 and an average particle diameter of 329 μm.21 Binary mixtures containing a target concentration of 95 and 85 mol % CO2 with CH4 and N2, respectively, were prepared from the above gases. The exact concentrations of the gas mixtures obtained by gas chromatography are shown in Table 1 which lists all of the experiments. A ternary CO2/N2/CH4 mixture with a target composition of 78/16/6 mol % was also prepared with the actual concentrations shown in Table 1. The incipient hydrate equilibrium formation pressures were determined by the wellknown isothermal pressure search method.18,19 The use of the calorimeter to obtain equilibrium data is briefly described.19 The HP-μDSC 7 Evo, Setaram high pressure calorimeter was used to detect and measure the heat transfer when gas hydrate formed and dissociated. Double-stage temperature control with Peltier coolers was used in the HPμDSC to provide a programmable temperature scanning

system in the region where hydrate crystals form. From a hydrate equilibrium perspective O2 and N2 form hydrates under similar conditions and thus one may only consider the N2. Finally, the reservoir water contains dissolved electrolytes, and thus salinity is an additional factor. In this work, the phase equilibria of CO2, CO2/CH4, CO2/ N2, and CO2/N2/CH4 gas mixtures were determined in pure water and 2 and 4 wt % NaCl solutions at temperatures found in depleted hydrocarbon reservoirs. The measurements were carried out by following the isothermal pressure search method as well as high pressure calorimetry.18−20

2. EXPERIMENTAL METHODS The CO2, CH4, and N2 gas with 99.5%, 97.97%, and 99.999% purities respectively were obtained from Praxair. Sodium chloride (NaCl) was obtained from Fisher Scientific. The silica B



Article

cooled from 288.15 to 248.15 K at the rate of 0.1 K/min to form gas hydrate and were heated from 248.15 to 288.15 K at the same rate to decompose the hydrate. Gas hydrate nucleation and dissociation are represented by exothermic and endothermic peaks, respectively. It is noted that all the experiments with the HP-μDSC were conducted three times. The list of the experiments using HP-μDSC is shown in Table 2.

between 228.15 and 393.15 K under the heating or cooling rate of 0.001 to 2 K/min. The standard uncertainties of the temperature and heat flow measurement are known to be 0.1 K and 0.05 mJ. The HP-μDSC has two 1 mL cells, a sample cell and a reference cell; each can sustain up to 40 MPa. Two types of sample holder were used. One is a droplet sample holder, and its description can be found elsewhere.22 Briefly, it is a customized stainless steel holder with four 1.5 mm diameter, 2.6 mm depth pits, and a 1.6 mm diameter, 7 mm length rod. The volume for each pit is 1 mL and 1 μL deionized water or 2 or 4 wt % NaCl solution was injected carefully into the pits using a microsyringe. Thus, the total volume of the injected water or solutions was 4 μL. The other sample holder (reservoir sample holder) is shown in Figure 1. It consists of

3. RESULTS AND DISCUSSION The measured CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %) and CO2/N2/CH4 (78/16/6 mol %) hydrate equilibrium pressures at 276.15, 277.15, and 278.15 K in water and 2 and 4 wt % NaCl solutions are shown in Table 1. The measured equilibrium pressures and the calculated values using the CSMGem software23 are shown in Figures 2 to 5.

Figure 1. Reservoir sample holder using an HP-μDSC.

a high-pressure Nylo-Seal Nylon tube with an inside diameter of 2.3 mm and inside height of 8 mm. The cylindrical tube was sealed at the bottom to make it a sample holder; 40 mg of silica sand was placed into the holder and 8.7 μL of aqueous solution was injected into the sand using a microsyringe to render it fully water saturated. The sample holder was then placed in the highpressure sample cell. The sample cell and the reference cell were pressurized to 1500 kPa with the gas hydrate forming gas. This was followed by depressurization. This operation was repeated two times to eliminate the air in the cells. Subsequently, the cells were pressurized to 3200 kPa and the temperature ramping program was started. The cells were

Figure 2. CO2 hydrate equilibrium pressures measured in the stirred high-pressure crystallizer and by high-pressure microdifferential scanning calorimetry in water, 2 and 4 wt % NaCl solutions.

Table 2. Hydrate Dissociation Temperatures and Endothermic Heat Measured under Constant 3200 kPa in a HP-μDSC in the Water Droplet and Water, 2 and 4 wt % NaCl Solutions Fully Saturated Reservoira droplet

reservoir

in water

in water

T/K sample gas/gas mixtures CO2

CO2/CH4 (95/5 mol %) #1: (95.10/4.90 mol %) #2: (95.03/4.97 mol %) #3: (94.95/5.05 mol %) CO2/N2 (85/15 mol %) #1: (85.03/14.97 mol %) #2: (84.83/15.17 mol %) #3: (84.94/15.06 mol %) CO2/N2/CH4 (78/16/6 mol %) #1: (78.02/15.89/6.09 mol %) #2: (77.98/15.98/6.04 mol %) #3: (77.85/16.06/6.09 mol %) a

in 2 wt % NaCl

T/K

in 4 wt % NaCl

T/K

T/K

this work

CSMGem

H/mJ

this work

H/mJ

this work

CSMGem

H/mJ

this work

CSMGem

H/mJ

280.8 280.9 280.8 280.6 280.6 280.7

280.7

482.3 492.4 488.1 469.1 447.7 453.9

280.6 280.6 280.6 280.5 280.6 280.6

3636.0 3696.7 3643.5 3404.0 3379.3 3309.1

279.8 279.8 279.7 279.8 279.9 279.8

279.8

3050.3 3098.4 3110.8 2798.0 2805.1 2765.2

278.9 278.8 278.9 278.9 279.0 278.9

279.0

2204.5 2185.9 2238.6 1920.3 1895.4 1919.0

279.6 279.5

279.5

449.7 439.0

279.6 279.4

2980.4 3008.8

278.6 278.7

278.7

2490.6 2491.3

277.7 277.8

277.8

446.2 433.0 435.1 427.8

279.6 279.3 279.4 279.4

2973.3 2898.9 2878.1 2937.4

278.5 278.5 278.4 278.5

2439.7 2426.9 2419.8 2400.5

277.7 277.7 277.6 277.6

279.6 279.3 279.3 279.3

280.7

279.4

279.9

278.6

279.0

277.7

1537.7 1572.8 1598.5 1522.7 1530.9 1519.4

Standard uncertainties u is u(T) = 0.1 K and u(H) = 0.05 mJ. C



Article

The measured hydrate equilibrium pressures are in a good agreement with the calculated values (within ±40 kPa). Figure 6 shows the typical heat flow of the water reservoir sample holder in the system of CO2/CH4 (95/5 mol %) in the

Figure 3. CO2/CH4 (95/5 mol %) hydrate equilibrium pressures measured in the stirred high-pressure crystallizer and by high-pressure microdifferential scanning calorimetry in water and 2 and 4 wt % NaCl solutions. Figure 6. Typical heat flow of the water reservoir sample holder in the system of CO2/CH4 (95/5 mol %) obtained using the temperature ramping protocol in a HP-μDSC. (Cooling, 288 to 248 K; ramping, 248 to 288 K; all at 3200 kPa).

cooling and ramping experiments in a HP-μDSC at 3200 kPa. The exothermal peaks corresponding to CO2 liquidation, ice, and hydrate nucleation were observed when the sample was cooled from 288 to 248 K. On the other hand, endothermal peaks corresponding to CO2 vaporization, ice melting, and hydrate dissociation were observed when the system was reheated from 248 to 288 K. The measured hydrate equilibrium dissociation temperatures and endothermic heat under constant pressure of 3200 kPa in a HP-μDSC in the water droplet and water and 2 and 4 wt % NaCl solutions fully saturated reservoir are shown in Table 2. Figure 7 shows the hydrate dissociation Figure 4. CO2/N2 (85/15 mol %) hydrate equilibrium pressures measured in the stirred high-pressure crystallizer and by high-pressure microdifferential scanning calorimetry in water and 2 and 4 wt % NaCl solutions.

Figure 7. Hydrate dissociation peaks for four hydrate forming systems observed with HP-μDSC in the droplet sample holder under a 0.1 K/ min heating protocol. Figure 5. CO2/N2/CH4 (78/16/6 mol %) hydrate equilibrium pressures measured in the stirred high-pressure crystallizer and by high-pressure microdifferential scanning calorimetry in water and 2 and 4 wt % NaCl solutions.

peaks for CO2, CO2/CH4 (95/5 mol %), CO2/N2 (85/15 mol %), and CO2/N2/CH4 (78/16/6 mol %) gas or gas mixture hydrate forming systems observed with HP-μDSC in the water droplet sample holder under a 0.1 K/min heating protocol. The presence of 5 mol % of CH4 in the CO2/CH4 shows a very small effect on the hydrate dissociation temperatures as compared to the case with pure CO2. Calculations using CSMGem show that at a given temperature the hydrate

The saline solutions are expected to shift the hydrate equilibrium to a higher pressure region at constant temperature. D



Article

equilibrium pressure of CO2 increases by about 35 kPa when hydrates form from a CH4/CO2 mixture containing 5 mol % CH4.23 Note that the baseline of the heat flow curves started at different values of the heat flow. However, the measurement conducted in this work focused on the hydrate dissociation temperature (peak start point) and the amount of heat absorbed (integration of the peak area) when hydrate dissociated. The hydrate dissociation temperature shifts to a lower region when N2 or N2 and CH4 are added to CO2. The endothermic heat measured during the dissociation of hydrate in the HPμDSC is also shown in Table 2. It is noted that during the CO2/N2 (85/15 mol %) hydrate dissociation process a second and much smaller endothermic peak is observed at about 280 K, but the origin is not known. The measured hydrate dissociation temperatures show 0.1 to 0.2 K differences from the calculated values. Figures 8 to 11 show the hydrate dissociation peaks for hydrates formed by the CO2, CO2/CH4 (95/5 mol %), CO2/

Figure 10. Hydrate dissociation peaks for hydrate formed by the CO2/ N2 (85/15 mol %) gas mixture in deionized water and 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol.

Figure 11. Hydrate dissociation peaks for the hydrate formed by the CO2/N2/CH4 (78/16/6 mol %) gas mixture in deionized water and 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol.

Figure 8. CO2 hydrate dissociation peaks for hydrate formed in deionized water and 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol.

the water droplet sample holder, the presence of N2, CH4, or N2/CH4 in the CO2 shifted the hydrate dissociation temperature to a lower region. The increase in salinity in the reservoir resulted in lower hydrate dissociation temperatures at a constant pressure of 3200 kPa. The hydrate dissociation endothermic heat also showed a decreasing trend with an increase in salinity in the reservoir, which indicates that less hydrate is formed. It is of note that the hydrate dissociation process in 2 and 4 wt % NaCl reservoirs lasted a longer period as compared to the hydrate dissociation in the water reservoir. Because NaCl is excluded from the hydrate lattice, the salinity of the aqueous solution increases as hydrate formation proceeds. Similarly, when the hydrate decomposes, the salinity is restored as water is being released. The incipient equilibrium hydrate formation points correspond to the presence of an infinitesimal amount of hydrate (onset of hydrate formation) or when an infinitesimal amount of hydrate remains undissociated.18,19,22 It is also noted that the measured hydrate dissociation temperatures in the reservoir sample holders show ±0.2 K difference from the calculated values.23 The percentage of water converted to hydrate was calculated on the basis of the endothermic heat measured when hydrate dissociates in the HP-μDSC. It is known that the enthalpy change is 65 kJ/mol and the hydration number is 6.17 for the

Figure 9. Hydrate dissociation peaks for hydrate formed by the CO2/ CH4 (95/5 mol %) gas mixture in deionized water and 2 and 4 wt % NaCl solutions observed with the HP-μDSC in the reservoir sample holder under a 0.1 K/min heating protocol.

N2 (85/15 mol %), and CO2/N2/CH4 (78/16/6 mol %) in deionized water and 2 and 4 wt % NaCl solutions. The measured hydrate dissociation temperatures and the calculated data are shown in Table 2. Similar to the measurements with E



Article

CO2 hydrate.23,24 Results showed that about 21% of the initial water in the droplet sample holders formed hydrate, which is much less than the 72% of the water conversion in the reservoir sample holder. This observation is consistent with experimental findings reported in the literature for sand beds.25 It is noted that the enhanced rate in the presence of a porous medium created by sand prompted further work with other media in an effort to optimize the clathrate hydrate processes for CO2 capture.26,27 The water conversion in the reservoir samples containing 2 and 4 wt % NaCl solutions was found to be 61 and 43%, respectively, indicating less hydrate formed at higher salinity which is expected as the pressure is constant. The equilibrium data presented in this work are useful for the design of processes relevant to CO2 storage in depleted natural gas reservoirs at conditions where gas hydrates form.

(6) Kumar, R.; Moudrakovski, I.; Ripmeester, J. A.; Englezos, P. Structure and composition of CO2/H2 and CO2/H2/C3H8 hydrate in relation to simultaneous CO2 capture and H2 production. AIChE J. 2009, 55, 1584−1594. (7) Kumar, R.; Linga, P.; Ripmeester, J. A.; Englezos, P. A two-stage clathrate hydrate/membrane process for pre-combustion capture of carbon dioxide and hydrogen. J. Environ. Eng. 2009, 135, 411−417. (8) White, C. M.; Strazisar, B. R.; Granite, E. J.; Hoffman, J. S.; Pennline, H. W. Separation and capture of CO2 from large stationary sources and sequestration in geological formations − coalbeds and deep saline aquifers. J. Air Waste Manage. Assoc. 2003, 53, 645−715. (9) Cote, M. M.; Wright, J. F. Preliminary assessment of the geological potential for sequestration of CO2 as gas hydrate in the Alberta portion of the Western Canada Sedimentary Basin. Geological Survey of Canada, Open File 65822013; DOI: 10.4095/292515 (10) Zatsepina, O. Y.; Pooladi-Darvish, M. Storage of CO2 hydrate in shallow gas reservoirs: pre-and post-injection periods. Greenhouse Gases: Sci. Technol. 2011, 1, 223−236. (11) Zatsepina, O. Y.; Pooladi-Darvish, M. Storage of CO2 as hydrate in depleted gas reservoirs. SPE Reservoir Eval. Eng. 2012, 15, 98−108. (12) Sun, D.; Englezos, P. Storage of CO2 in a partially water saturated porous medium at gas hydrate formation conditions. Int. J. Greenhouse Gas Control 2014, 25, 1−8. (13) Gunter, W. D.; Bachu, S.; Benson, S. The role of hydrogeological and geochemical trapping in sedimentary basins for secure geological storage of carbon dioxide. Geol. Soc. Spec. Publ. 2004, 233, 129−145. (14) Holloway, S. Underground sequestration of carbon dioxide - a viable greenhouse gas mitigation option. Energy 2005, 30, 2318−2333. (15) Gunter, W. D.; Wong, S.; Cheel, D. B.; Sjostrom, G. Large CO2 sinks: their role in the mitigation of greenhouse gases from an international, national (Canadian) and provincial (Alberta) perspective. Appl. Energy 1998, 61, 209−227. (16) Shukla, R.; Ranjith, P.; Haque, A.; Choi, X. A review of studies on CO2 sequestration and caprock integrity. Fuel 2010, 89, 2651− 2664. (17) Sun, D.; Englezos, P. CO2 storage capacity in laboratory simulated depleted hydrocarbon reservoirsImpact of salinity and additives. J. Nat. Gas Sci. Eng. 2016. 10.1016/j.jngse.2016.03.043 (18) Englezos, P.; Bishnoi, P. R. Experimental Study on the Equilibrium Ethane Hydrate Formation Conditions in Aqueous Electrolyte Solutions. Ind. Eng. Chem. Res. 1991, 30, 1655−1659. (19) Daraboina, N.; Ripmeester, J. A.; Walker, V. K.; Englezos, P. Natural Gas Hydrate Formation and Decomposition in the Presence of Kinetic Inhibitors. 1. High Pressure Calorimetry. Energy Fuels 2011, 25, 4392−4397. (20) Kharrat, M.; Dalmazzone, D. Experimental determination of stability conditions of methane hydrate in aqueous calcium chloride solutions using high pressure differential scanning calorimetry. J. Chem. Thermodyn. 2003, 35, 1489−1505. (21) Haligva, C.; Linga, P.; Ripmeester, J. A.; Englezos, P. Recovery of Methane from a Variable-Volume Bed of Silica Sand/Hydrate by Depressurization. Energy Fuels 2010, 24, 2947−2955. (22) Sharifi, H.; Ripmeester, J.; Walker, V. K.; Englezos, P. Kinetic inhibition of natural gas hydrates in saline solutions and heptane. Fuel 2014, 117, 109−117. (23) Sloan, E. D.; Koh, C. A. Clathrate Hydrates of Natural Gases; CRC Press, LLC: Boca Raton, FL, 2008. (24) Kang, S. P.; Lee, H.; Ryu, B. J. Enthalpies of dissociation of clathrate hydrates of carbon dioxide, nitrogen, (carbon dioxide + nitrogen), and (carbon dioxide + nitrogen + tetrahydrofuran). J. Chem. Thermodyn. 2001, 33, 513−521. (25) Linga, P.; Daraboina, N.; Ripmeester, J. A.; Englezos, P. Enhanced rate of gas hydrate formation in a fixed bed column filled with sand compared to a stirred vessel. Chem. Eng. Sci. 2012, 68, 617− 623. (26) Babu, P.; Kumar, R.; Linga, P. Pre-combustion capture of carbon dioxide in a fixed bed reactor using the clathrate hydrate process. Energy 2013, 50, 364−373.

4. CONCLUSIONS The phase equilibria in hydrate forming systems relevant to the storage of CO2 in depleted natural gas reservoirs was determined by following the isothermal pressure search method in a stirred autoclave and by high pressure calorimetry. The incipient hydrate equilibrium pressures measured in the stirred autoclave are in a good agreement with the calculated values (within ±40 kPa). The hydrate dissociation temperatures determined by calorimetry on droplets and a porous media (reservoir) sample holder also show good agreement with the calculated values (within ±0.2 K). The effect of saline water was also determined. Salinity shifts hydrate equilibria to higher pressure at constant temperature or to a lower dissociation temperature region at constant pressure, as expected. Correspondingly the amount of hydrate formed is reduced. Results indicate that 40 to 60% of the original water formed hydrate when CO2 was injected into a typical saline model reservoir sample.

■

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected] Tel: +1 604-822-6184. Fax: +1 604-822-6003. Address: Department of Chemical and Biological Engineering, University of British Columbia, 2360 East Mall, Vancouver, BC, Canada V6T 1Z3. Funding

Financial support from Carbon Management Canada (CMC) Research Grant is appreciated. Notes

The authors declare no competing financial interest.

■

REFERENCES

(1) Davidson, D. W. Clathrate hydrates. In Franks, F., Eds.; Water A Comprehensive Treatise, Vol. 2. Water in Crystalline Hydrates Aqueous Solutions of Simple Nonelectrolytes; Plenum Press: New York, 1973. (2) Ripmeester, J. A. Hydrate Research-From Correlations to a Knowledge-based Discipline: The Importance of Structure. Ann. N. Y. Acad. Sci. 2000, 912, 1−16. (3) Englezos, P. Clathrate Hydrate. Geological carbon storage. Ind. Eng. Chem. Res. 1993, 32, 1251−1274. (4) Linga, P.; Kumar, R.; Englezos, P. The clathrate hydrate process for post and pre-combustion capture of carbon dioxide. J. Hazard. Mater. 2007, 149, 625−629. (5) Kumar, R.; Lang, S.; Englezos, P.; Ripmeester, J. A. Application of the ATR-IR spectroscopic technique to the characterization of hydrates formed by CO2, CO2/H2 and CO2/H2/C3H8. J. Phys. Chem. A 2009, 113, 6308−6313. F



Article

(27) Babu, P.; Kumar, R.; Linga, P. Medium pressure hydrate based gas separation (HBGS) process for pre-combustion capture of carbon dioxide employing a novel fixed bed reactor. Int. J. Greenhouse Gas Control 2013, 17, 206−214.

G


H2O System in the Hydrate

Recommend Documents