Estimating the Hydrate Safety Margin in the ... - ACS Publications

May 12, 2006 - Estimating the Hydrate Safety Margin in the Presence of Salt and/or Organic Inhibitor Using Freezing Point Depression Data of Aqueous ...
0 downloads 0 Views 114KB Size
Download PDF
Ind. Eng. Chem. Res. 2006, 45, 4441-4446

4441

CORRELATIONS Estimating the Hydrate Safety Margin in the Presence of Salt and/or Organic Inhibitor Using Freezing Point Depression Data of Aqueous Solutions Hesam Najibi,*,† Amir H. Mohammadi,‡ and Bahman Tohidi‡ Faculty of Petroleum Engineering, Petroleum UniVersity of Technology (PTU), Ahwaz, Iran, and Centre for Gas Hydrate Research, Institute of Petroleum Engineering, Heriot-Watt UniVersity, Edinburgh EH14 4AS, Scotland, U.K.

Developing systematic methods for controlling and monitoring gas hydrate risks along the pipeline and/or downstream conditions could provide the solution for future challenges. In this paper, the possibility of predicting the hydrate suppression temperatures of fluids from freezing point depression data of aqueous solutions containing different concentrations of salt and/or non-hydrate-forming organic inhibitor is investigated by developing a general correlation. The developed correlation considers only the changes in the freezing point of the aqueous solution, and there is no need for the analytical composition of the aqueous solution. Since measurement of the freezing point for the aqueous phase is much easier than measuring the hydrate dissociation point, such a relation can reduce the experimental costs. A well-proven thermodynamic model is used for generating pseudoexperimental data of hydrate suppression and freezing point depression for 160 different aqueous solutions containing various salts and/or organic inhibitors over a wide range of concentrations in order to develop this correlation. To examine the reliability of this model in predicting the freezing point depression, some experimental freezing point depression data are measured and compared with literature data and the predictions of the model. Independent data are used to examine the reliability of this method. The predictions of this approach are in acceptable agreement with the independent experimental data, demonstrating the reliability of this predictive method. 1. Introduction Application of extended subsea tiebacks and transportation of unprocessed well streams are among favorable options for reducing field development and operational costs. These pipelines normally convey a cocktail of multiphase fluids, including formation water and liquid and gaseous hydrocarbons, and may therefore be prone to hydrate formation, which potentially can block the pipeline and lead to serious operational and safety problems. The conventional method to prevent or reduce hydrate risks in transfer lines and process facilities is to use the socalled “thermodynamic inhibitors”. These are water-soluble chemicals that reduce the water activity, hence shifting the hydrate phase boundary to higher pressure and/or lower temperature conditions. The common industry practice is to use methanol or glycols. However, due to uncertainties in the inhibitor losses to other phases, changes in the system variables (e.g., water cut, hydrocarbon rates, seasonal temperature changes) hydrate could form.1 Downstream monitoring could significantly reduce the risks associated with gas hydrate formation. However, systematic ways of controlling and monitoring along the pipeline to examine the degree of inhibition are very limited. Hydrate monitoring systems can be produced based on simple techniques such as freezing point depression measurement of aqueous phase. * To whom correspondence should be addressed. E-mail: [email protected] or [email protected]. † PTU. ‡ Heriot-Watt University.

In the 1930s Hammerschmidt2 presented an equation for predicting hydrate supression of typical natural gases in contact with dilute aqueous solutions of antifreeze agents such as methanol. The equation is

∆T )

1,297W M(100 - W)

(1)

where M is the molecular weight of the antifreeze agent, W is the weight percent of the antifreeze agent in the solution, and ∆T is the hydrate supression in kelvin. This correlation is independent of pressure, hydrocarbon composition, and hydrate structure, but it is dependent on the type and amount of inhibitor present in the aqueous solution. Other investigators after Hammerschmidt2 have correlated the degree of hydrate inhibition in terms of the amount and nature of the inhibitor present in the system.3-9 Recently, a review article explained the existing correlations in detail.9 In this paper, we report the results of our study into using the freezing point of aqueous solutions for estimating the hydrate inhibition characteristics. A successful outcome could significantly simplify the hydrate management strategy using sampling or online measurements. We correlate the degree of hydrate inhibition directly to the freezing point depression due to the presence of salt and/or organic inhibitor in the aqueous phase, regardless of the type and amount of salt and/or inhibitor present in the system, eliminating the need for compositional analysis of the aqueous phase. The hydrate stability zone in the presence of the salt and/or organic inhibitor could be determined by combining the results of the above correlation with the

10.1021/ie051265v CCC: $33.50 © 2006 American Chemical Society Published on Web 05/12/2006

4442

Ind. Eng. Chem. Res., Vol. 45, No. 12, 2006

Table 1. Measured Freezing Point Temperatures for Different Aqueous Solutions wt % NaCl ( 0.1

wt % EG ( 0.1

wt % methanol ( 0.1

freezing point ( 0.2, K

1.0 3.0 5.0 7.0 10.0 0.0 0.0 0.0 0.0 0.0 3.2 4.2 7.0 8.2 7.1 6.3 10.2 12.8 12.4

0.0 0.0 0.0 0.0 0.0 10.0 20.0 30.0 40.0 50.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.8 4.2 6.4 7.8 11.5 12.9 10.1 10.8 12.9

272.7 271.4 270.0 268.5 266.4 269.6 264.8 258.3 249.2 236.2 269.0 267.1 263.0 260.4 258.0 257.5 255.9 252.1 250.1

Figure 1. Comparison of freezing point data for aqueous solutions of NaCl. *, measured value; 9, CRC handbook data; solid curve, thermodynamic model1,12,13,20,21 prediction.

measured/predicted hydrate stability zone for hydrocarbon systems in the presence of distilled water.10 Clearly, this equation cannot provide reliable results for thermodynamic inhibitors that take part in hydrate formation (e.g., 2-propanol11). 2. Thermodynamic Model and Data Generation The required freezing point depression and hydrate suppression data have been generated using a well-proven thermodynamic model,1,12,13 for 160 different aqueous solutions containing various salts and/or organic inhibitors over a wide range of concentrations. The data generated from thermodynamic model was preferred to real experimental data for the following reasons: (1) The amount of experimental hydrate dissociation data and freezing point data, especially in the presence of salts and/or organic inhibitors, is very limited.14,15 (2) Because of the limited experimental data, any error could easily result in unreliable correlation. A detailed description of the model is given elsewhere.1,12,13 Briefly, the comprehensive thermodynamic model uses the Valderrama modification of the Patel and Teja equation of state (VPT-EOS)16 for fugacity calculations in all fluid phases. Nondensity-dependent (NDD) mixing rules17 are applied to model polar-nonpolar and polar-polar interactions. The hydrate phase is modeled using the solid solution theory of van der Waals and Platteeuw.18 The Kihara model for spherical molecules19 is applied to calculate the potential functions for compounds forming the hydrate phase. The presence of salt(s) in aqueous solution is taken into account by coupling the equation of state (short-range interactions) with a Debye-Hu¨ckel (D-H) electrostatic term (long-range interactions).1,20,21 3. Results and Discussion The reliability of the thermodynamic model in predicting the hydrate stability zones of reservoir fluids in the presence of aqueous solutions of various salts and/or organic inhibitors has been demonstrated in previous publications.1,12,13,20,21 To demonstrate the reliability of this model in predicting the freezing point depression of aqueous solutions containing salts and/or organic inhibitors, data on some systems have been measured. The experimental method is explained in detail elsewhere.22 Briefly, the freezing points were measured using a simple and reliable method based on the difference between the bath and

Figure 2. Comparison of freezing point data for aqueous solutions of EG. *, measured value; 9, CRC handbook data; solid curve, thermodynamic model1,12,13,20,21 prediction.

sample temperature relying on detection of the latent heat required to melt ice within a sample. The measured freezing point data are given in Table 1. The freezing point data measured for NaCl aqueous solution and aqueous solution of ethylene glycol (EG) are compared with the data reported in the CRC handbook23 and the prediction of the thermodynamic model1,12,13 in Figures 1 and 2, respectively. The data measured for aqueous solutions of methanol and NaCl are compared with the prediction of the thermodynamic model1,12,13 in Figure 3. It should be mentioned that none of the freezing points measured and reported in this work have been used in developing the thermodynamic model. As can be seen in Figures 1-3, the agreement between experimental data and the predictions of the thermodynamic model1,12,13 is good, demonstrating the reliability of the model. As mentioned earlier, freezing point depression and hydrate suppression data for 160 different aqueous solutions with a large number of salts and/or organic inhibitors over a wide range of concentrations (as shown in Table 2) were used in developing the correlation. The hydrate suppression temperatures of methane at 20 MPa were used for developing the correlation, and the effect of the hydrocarbon composition as well as the system pressure was ignored as previously mentioned by Nielsen and Bucklin,3 Carroll,7 and Mohammadi and Tohidi.9 The predicted hydrate suppression temperatures were plotted versus the freezing point depressions for the systems shown in Table 2. Figure 4 shows the collapse of all the data onto a

Ind. Eng. Chem. Res., Vol. 45, No. 12, 2006 4443

Figure 3. Comparison of measured freezing point data and predictions of thermodynamic model1,12,13,20,21 for aqueous solutions of methanol + NaCl.

Figure 5. Experimental25 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of NaCl aqueous solutions. Gas composition: C1 (80 mol %) + CO2 (20 mol %). 9, 5% NaCl; 2, 10% NaCl; b, 15% NaCl; [, 20% NaCl; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Table 2. Concentrations of Salt and/or Organic Inhibitor Used in Developing the Correlationa inhibitor NaCl KCl CaCl2 KBr NaBr HCOONa HCOOK methanol ethanol EG diethylene glycol triethylene glycol methanol + NaCl methanol + KCl a

organic inhibitor, wt % salt, wt % no. of data points 0 0 0 0 0 0 0 2.8-50 4.2-31.1 5.8-23.1 7-49 7.9-59.5 3.1-14.2 2.9-11

2-23 2-13 2-32 2-32 2-40 2-30 2-30 0 0 0 0 0 3.2-12.5 3-9.7

12 7 16 16 20 15 15 18 8 4 7 8 9 5

Concentrations are relative to aqueous solutions.

Figure 6. Experimental25 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of KCl aqueous solutions. Gas composition: C1 (80 mol %) + CO2 (20 mol %). 9, 5% KCl; 2, 10% KCl; b, 15% KCl; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

solutions containing salts and/or organic inhibitors to the aqueous phase freezing point depression, is given by the following expression:

T ) T0 - 0.6825∆TF

Figure 4. Hydrate suppression temperature for methane hydrates vs freezing point depression temperature in the presence of aqueous solutions containing salt and/or organic inhibitor.

straight line, suggesting a linear relationship between hydrate suppression temperatures and freezing point depressions with a slope of 0.6825. As can be seen, the hydrate suppression temperature is always less than the corresponding freezing point depression, which is in good agreement with that mentioned by Nielsen and Bucklin,3 Sloan,24 Carroll,7 and Mohammadi and Tohidi.9 Nielsen and Bucklin3 derived an equation indicating that the hydrate suppression temperature will always be less than the freezing point depression by a factor of [1 - (heat of fusion of ice)/(heat of hydrate dissociation)]. The correlation, which relates the hydrate dissociation temperature of the reservoir fluid in the presence of aqueous

(2)

where T is the hydrate dissociation temperature in kelvin, ∆TF stands for the freezing point depression of the aqueous solution in kelvin, and T0 represents the hydrate dissociation temperature of the same fluid in the presence of distilled water in kelvin. The developed correlation is simple and enables fast estimation of the hydrate-free zone of various reservoir fluids, in the presence of salts and/or organic inhibitors regardless of the system pressure and hydrate structure. The only prerequisite to use the correlation is the hydrate dissociation temperature of the same fluid in the presence of distilled water (T0), which can be calculated using a general correlation10 capable of predicting hydrate phase boundaries of various reservoir fluids at temperatures less than 293.15 K. The results predicted by the newly developed correlation are compared with independent experimental data reported in the literature in Figures 5-14. In all comparisons the value of ∆TF is calculated using the thermodynamic model mentioned in the previous section.1,12,13 Also, all thermodynamic inhibitor concentrations reported here are relative to the aqueous phase. In all figures, the predictions of the thermodynamic model are also reported.

4444

Ind. Eng. Chem. Res., Vol. 45, No. 12, 2006

Figure 7. Experimental25 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of CaCl2 aqueous solutions. Gas composition: C1 (80 mol %) + CO2 (20 mol %). 9, 9.9% CaCl2; 2, 15% CaCl2; b, 20% CaCl2; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Figure 8. Experimental26 and predicted (correlation and thermodynamic model1,12,13,20,21) methane hydrate stability zones in the presence of methanol aqueous solutions. 0, 10% methanol; 4, 20% methanol; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Figure 9. Experimental27 and predicted (correlation and thermodynamic model1,12,13,20,21) methane hydrate stability zones in the presence of EG aqueous solutions. 0, 10% EG; 4, 30% EG; O, 50% EG; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Figures 5-7 show a comparison between predictions of the correlation developed in this work and the experimental data reported by Dholabhai and Bishnoi25 for hydrate dissociation conditions of a gas mixture composed of 80 mol % methane and 20 mol % carbon dioxide in the presence of various salt aqueous solutions. As can be seen, the predictions of the newly developed correlation are in good agreement with the experimental data. It should be mentioned that the wide difference

Figure 10. Experimental28 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of methanol aqueous solutions. Gas composition: methane (95.01 mol %) + propane (4.99 mol %). 0, 10% methanol; 4, 20% methanol; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Figure 11. Experimental28 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of methanol aqueous solutions. Gas composition (mol %): C1 ) 84.13%; C2 ) 4.67%; C3 ) 2.34%; n-C4 ) 0.93%; n-C5 ) 0.93%; N2 ) 7%. 0, 10% methanol; 4, 20% methanol; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

Figure 12. Experimental28 and predicted (correlation and thermodynamic model1,12,13,20,21) hydrate stability zones in the presence of methanol aqueous solutions. Gas composition (mol %): C1 ) 71.6%; C2 ) 4.73%; C3 ) 1.94%; n-C4 ) 0.79%; n-C5 ) 0.79%; N2 ) 5.69%; CO2 ) 14.19. 0, 10% methanol; 4, 20% methanol; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions.

between the solubility of methane and that of carbon dioxide in the aqueous phase does not seem to have any important effect on the accuracy of the results. However, this effect may be important in sour fluids with very high concentrations of acid gases.1

Ind. Eng. Chem. Res., Vol. 45, No. 12, 2006 4445

Figure 13. Experimental29 and predicted (correlation and thermodynamic model1,12,13,20,21) methane hydrate stability zones in the presence of NaCl + methanol aqueous solutions. 9, 6.2% NaCl + 10% methanol; 2, 6.2% NaCl + 20% methanol; b, 6.2% NaCl + 30% methanol; [, 6.2% NaCl + 40% methanol; solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions. Solid points measured by technique using Cailletet equipment, and open points measured by Raman spectroscopy technique.

the prediction of the developed correlation in Figures 13 and 14. As shown in the figures, the predicted data are in acceptable agreement with the experimental data. However, the method presented in this work shows some deviations at very high concentrations of methanol. These deviations may be attributed to the uncertainties in the experimental data at high concentrations of inhibitors.21 Jager et al.29 used two different techniques for measuring methane hydrate phase boundaries in the presence of aqueous solutions containing methanol and NaCl. In the first technique they used Cailletet apparatus, and the second technique involves Raman spectroscopy. Their reported data show some deviations at high concentrations of salts and organic inhibitors for the same conditions, indicating a need for generating accurate hydrate dissociation data at high concentrations of salts and organic inhibitors. The expression could be further developed with the availability of new data, in particular at high concentrations of salts and/or organic inhibitors. 4. Conclusions The possibility of using freezing point depression of aqueous solutions to predict the hydrate suppression temperatures of reservoir fluids in the presence of salts and/or organic inhibitors was investigated by developing a simple equation. Good agreement was achieved between the predictions of this equation and experimental data from the literature, demonstrating the reliability of the method developed in this work. Acknowledgment

Figure 14. Experimental29 and predicted (correlation and thermodynamic model1,12,13,20,21) methane hydrate stability zones in the presence of NaCl + methanol aqueous solutions. 9, 11.9% NaCl + 10% methanol; 2, 11.9% NaCl + 20% methanol; b, 11.9% NaCl + 30% methanol; [, 11.9% NaCl + 40% methanol; Solid curve, correlation predictions; dashed curve, thermodynamic model1,12,13,20,21 predictions. Solid points measured by technique using Cailletet equipment, and open points measured by Raman spectroscopy technique.

Figures 8 and 9 show a comparison between the predictions of this method and the experimental data reported by Ng and Robinson26 and Robinson and Ng27 for hydrate dissociation conditions of methane in the presence of methanol aqueous solutions and aqueous solutions of EG. As can be observed, the predictions are in good agreement with the experimental data. To examine the capability of this correlation for predicting the hydrate inhibition characteristics in structure II hydrate forming systems, the predictions of the developed correlation are compared with the experimental data reported by Ng and Robinson28 for hydrate dissociation conditions of different gas mixtures in the presence of methanol. The results are presented in Figures 10-12. Acceptable agreement between the predictions and the experimental data shows that the effect of gas composition and hydrate structure can be ignored for engineering purposes. Limited experimental data for hydrate dissociation conditions of gases in the presence of salts and organic inhibitors have been reported in the literature. Hydrate dissociation conditions of methane in the presence of different concentrations of methanol and NaCl reported by Jager et al.29 are compared with

This work was part of a Joint Industrial Project funded by a consortium consisting of Total, National Iranian Gas Company (NIGC), Hydro, British Petroleum (BP), Chevron, Statoil, and Petronas, whose support is gratefully acknowledged. H.N. wishes to thank the Petroleum University of Technology (PUT) for financial support during his sabbatical leave. List of Symbols D-H ) Debye-Hu¨ckel electrostatic term M ) molecular weight of antifreeze agent (g/g-mol) NDD ) non-density-dependent mixing rules T ) hydrate dissociation temperature (K) T0 ) hydrate dissociation temperature in the presence of distilled water (K) VPT-EOS ) Valderrama modification of the Patel and Teja equation of state W ) weight percent of antifreeze agent in aqueous solution ∆T ) hydrate suppression temperature (K) ∆TF ) freezing point depression (K) Literature Cited (1) Tohidi-Kalorazi, B. Gas Hydrate Equilibria in the Presence of Electrolyte Solutions. Ph.D. Thesis, Heriot-Watt University, 1995. (2) Hammerschmidt, E. G. Gas Hydrate Formations, A Further Study On Their Prevention and Elimination from Natural Gas Pipe Lines. Gas 1939, 15 (5), 30-34. (3) Nielsen, R. B.; Bucklin, R. W. Why not use methanol for hydrate control? Hydrocarbon Process. 1983, 62 (4), 71-78. (4) McCain, W. D. Reservoir-Fluid Property CorrelationssState of the Art. SPE ReserVoir Eng. 1991, May 266-272. [Also: McCain, W. D. The Properties of Petroleum Fluids, 2nd ed.; Pennwell Publishing: Tulsa, OK, 1990.] (5) Ouar, H.; Cha, S. B.; Wildeman, T. R.; Sloan, E. D. The formation of natural gas hydrates in water-based drilling fluids. Trans. Inst. Chem. Eng. 1992, 70 (A), 48 (quoted in ref 24).

4446

Ind. Eng. Chem. Res., Vol. 45, No. 12, 2006

(6) Yousif, M. H.; Young, D. B. A Simple Correlation to Predict the Hydrate Point Suppression in Drilling Fluids. SPE/IADC 25705, SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 1993. (7) Carroll, J. J. Natural Gas Hydrates: A Guide for Engineers; Gulf Professional Publishing: Houston, TX, 2003. (8) Østergaard, K. K.; Masoudi, R.; Tohidi, B.; Danesh, A.; Todd, A. C. A general correlation for predicting the suppression of hydrate dissociation temperature in the presence of thermodynamic inhibitors. J. Pet. Sci. Eng. 2005, 48 (1-2), 70-80. (9) Mohammadi, A. H.; Tohidi, B. A Novel Predictive Technique for Estimating the Hydrate Inhibition Effects of Single and Mixed Thermodynamic Inhibitors. Can J. Chem. Eng. 2005, 83 (6), 951-961. (10) Østergaard, K. K.; Tohidi, B.; Danesh, A.; Todd, A. C.; Burgass, R. W. A General Correlation for Predicting the Hydrate-Free Zone of Reservoir Fluids. SPE Prod. Facil. 2000, 15 (4), 228-233. (A free copy of this general correlation can be downloaded from http://www.pet.hw.ac.uk/ research/hydrate/index.html.) (11) Østergaard, K. K.; Tohidi, B.; Anderson, R.; Todd, A. C.; Danesh, A. Can 2-Propanol Form Clathrate Hydrate? Ind. Eng. Chem. Res. 2002, 41 (8), 2064, 2068. (12) Avlonitis, D. A. Thermodynamics of Gas Hydrate Equilibria. Ph.D. Thesis, Heriot-Watt University, 1992. (13) Tohidi, B.; Burgass, R. W.; Danesh, A.; Todd, A. C. Hydrate inhibition effect of produced water, Part 1. Ethane and propane simple gas hydrates. SPE 26701, SPE Offshore Europe 93 Conference; 1993; pp 255264. (14) Kan, A. T.; Fu, G.; Watson, M. A.; Tomson, M. B. Effect of hydrate inhibitors on oilfield scale formation and inhibition. SPE 74657, International Symposium on Oilfield Scale, Aberdeen, UK, 2002. (15) Mathews, P. N.; Subramanian, S.; Creek, J. High Impact, Poorly Understood Issues with Hydrates In Flow Assurance. 4th International Conference on Gas Hydrates, Yokohama, May 2002; pp 899-905. (16) Valderrama, J. O. A generalized Patel-Teja equation of state for polar and non-polar fluids and their mixtures. J. Chem. Eng. Jpn. 1990, 23 (1), 87-91. (17) Avlonitis, D.; Danesh, A.; Todd, A. C. Prediction of VL and VLL equilibria of mixtures containing petroleum reservoir fluids and methanol with a cubic EoS. Fluid Phase Equilib. 1994, 94, 181-216. (18) van der Waals, J. H.; Platteeuw, J. C. Clathrate solutions. AdV. Chem. Phys. 1959, 2, 2-57.

(19) Kihara, T. Virial Coefficient and Models of Molecules in Gases. ReV. Mod. Phys. 1953, 25 (4), 831-843. (20) Tohidi, B.; Danesh, A.; Todd, A. C. Modelling Single and Mixed Electrolyte-Solutions and Its Applications to Gas Hydrates. Chem. Eng. Res. Des. 1995, 73 (A4), 464-472. (21) Mohammadi, A. H.; Tohidi, B. Prediction of Hydrate Phase Equilibria in Aqueous Solutions of Salt and Organic Inhibitor Using a Combined Equation of State and Activity Coefficient based Model. Can J. Chem. Eng. 2005, 83 (5), 865-871. (22) Anderson, R.; Llamedo, M.; Tohidi, B.; Burgass, R. W., Experimental Measurement of Methane and Carbon Dioxide Clathrate Hydrate Equilibria in Mesoporous Silica. J. Phys. Chem. 2003, 107 (15), 35073514. (23) CRC Handbook of Chemistry and Physics, 69th ed.; CRC Press Inc.: Boca Raton, FL, 1988-1989. (24) Sloan, E. D. Clathrate Hydrates of Natural Gases, 2nd ed.; Marcel Dekker: New York, 1998. (25) Dholabhai, P. D.; Bishnoi, P. R. Hydrate Equilibrium Conditions in Aqueous Electrolyte Solutions: Mixtures of Methane and Carbon Dioxide. J. Chem. Eng. Data 1994, 39 (1), 191-194. (26) Ng, H. J.; Robinson, D. B. Hydrate formation in systems containing methane, ethane, propane, carbon dioxide or hydrogen sulfide in the presence of methanol. Fluid Phase Equilib. 1985, 21 (1-2), 145-155. (27) Robinson, D. B.; Ng, H. J. Hydrate formation and inhibition in gas or gas condensate streams. J. Can. Pet. Technol. 1986, 25 (4), 26-30. (28) Ng, H. J.; Robinson, D. B. Equilibrium Phase Composition and Hydrating Conditions in Systems Containing Methanol, Light Hydrocarbons, Carbon Dioxide and Hydrogen Sulfide. GPA Research Report RR-66; April 1983. (29) Jager, M. D.; Peters, C. J.; Sloan, E. D. Experimental determination of methane hydrate stability in methanol and electrolyte solutions. Fluid Phase Equilib. 2002, 193, 17-28.

ReceiVed for reView November 15, 2005 ReVised manuscript receiVed February 24, 2006 Accepted April 10, 2006 IE051265V