Do We Have New Solutions to the Old Problem of Gas Hydrates?

Apr 3, 2012 - Kingdom. ABSTRACT: Gas hydrates are crystalline compounds formed as a result of the combination of suitable size gas molecules and...
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Do We Have New Solutions to the Old Problem of Gas Hydrates? Bahman Tohidi,* Ross Anderson, Antonin Chapoy, Jinhai Yang, and Rhoderick W. Burgass Centre for Gas Hydrate Research, Institute of Petroleum Engineering, Heriot-Watt University, Edinburgh EH14 4AS, United Kingdom ABSTRACT: Gas hydrates are crystalline compounds formed as a result of the combination of suitable size gas molecules and water under suitable pressure and temperature conditions. They resemble ice but unlike ice can form at temperatures well above the ice formation temperature. Their formation in oil and gas pipelines could result in serious operational problems and safety concerns. The conventional techniques in avoiding gas hydrate problems are dehydration, insulation, and/or heating or injection of thermodynamic or low-dosage hydrate inhibitors. In this paper, we discuss some new techniques for preventing gas hydrate problems that could improve the reliability of hydrate prevention techniques and/or reduce the associated costs. The new solutions include hydrate safety margin monitoring, early hydrate detection systems, and the latest results and techniques for evaluating low-dosage hydrate inhibitors. The application of thermodynamic modeling to CO2-rich systems will also be presented.

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INTRODUCTION Gas hydrates can cause serious problems in the production and transport of hydrocarbon reservoir fluids, in particular in deepwater production and transportation of unprocessed well streams.1 Conventional techniques in preventing gas hydrate problems include dehydration, injection of thermodynamic inhibitors (alcohols and glycols), maintaining the system temperature outside the hydrate stability zone (e.g., insulation and/or heating), using low-dosage hydrate inhibitors [LDHIs, i.e., kinetic hydrate inhibitors (KHIs) and/or anti-agglomerants], or a combination of the above. Perhaps the oldest technique is injection of thermodynamic inhibitors (i.e., antifreeze), which dates back to the 1930s,2 whereas the newest technique is application of LDHIs.3−6 Although the existing techniques have served the industry well over the last 80 years, there is a need for improved techniques and a better understanding because the costs associated with a hydrate blockage are becoming ever greater with the industry moving to deeper waters and longer tiebacks. Another area that is attracting significant interest is the risk of hydrate formation in transport and storage of CO2-rich systems. Although the current techniques in preventing gas hydrate problems in CO2-rich systems are based on dehydration, the nature of the fluid systems and limited relevant experimental data present significant challenges with respect to modeling/ prediction.7 The main objective of this paper is to discuss the latest developments in avoiding gas hydrate problems that could reduce the associated costs and improve the reliability of preventing and monitoring techniques. The techniques discussed include (1) hydrate safety margin monitoring, (2) detecting early signs of hydrate formation, (3) new techniques for evaluating KHIs, and (4) advances in thermodynamic modeling.

temperature at the system pressure. If at any given pressure the system temperature is outside the hydrate stability zone, then no hydrate formation is expected; otherwise, there is a risk of hydrate formation. The system temperature and pressure conditions could be calculated using various predictive techniques and software packages. Alternatively, one can assume maximum system pressure and minimum system temperature for designing a hydrate prevention strategy. Knowing the hydrocarbon fluid and aqueous phase compositions, it should be possible to determine the hydrate stability zone. Superimposing the system pressure and temperature profile and the hydrate stability zone, one can determine if there is a risk of hydrate formation. If the system pressure and temperature profile is inside the hydrate stability zone, then there is a risk of hydrate formation, as shown in Figure 1.

Figure 1. Hydrate stability zone and pipeline pressure and temperature profile for a typical offshore pipeline. As shown in the figure, the wellhead conditions are outside the hydrate stability zone. The pipeline conditions enter the hydrate stability zone because of pressure and temperature changes. The system conditions could be outside the hydrate stability zone at receiving facilities.

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Special Issue: Upstream Engineering and Flow Assurance (UEFA)

MONITORING HYDRATE SAFETY MARGIN Hydrate safety margin could be defined as the difference between the temperature of the system and hydrate stability © 2012 American Chemical Society

Received: February 6, 2012 Revised: March 31, 2012 Published: April 3, 2012 4053

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Knowing the hydrocarbon fluid composition, it is possible to determine the hydrate stability zone. Superimposing the pipeline pressure and temperature condition can determine the hydrate safety margin and whether enough inhibitor is being injected or the amount of inhibitor is too much, as shown in Figure 2. The technique has been field-trialed in various places around the world,8,9 including a case where the amount of injected inhibitor was reduced significantly.10 The above technique has successfully been used for determining the amount of KHIs in laboratory and field applications.11 The results show that the technique is robust, reliable, and very fast compared to alternative methods for determining the amount of inhibitors. Research and development are ongoing to develop an online version of the technique. An alternative technique has been developed for determining the hydrate stability zone when there is no access to an aqueous phase. The technique is based on determining the amount of water in the gas phase. The amount of water in the gas phase is directly related to the activity of water, hence, amount of salts and/or thermodynamic inhibitors. Knowing the amount of water in the gas phase, it is possible to determine the hydrate stability zone, hence, hydrate safety margin. Various techniques and devices have been evaluated/tested for determining the amount of water in the gas phase, including systems based on laser and capacitance.12

As mentioned earlier, injection of an inhibitor is among various techniques used for avoiding gas hydrate problems. Thermodynamic inhibitors shift the hydrate stability zone to the left, resulting in conditions where the system pressure and temperature are outside the hydrate stability zone, as shown in Figure 2. In general, predictive and/or experimental techniques

Figure 2. Hydrate safety margin monitoring. Knowing the hydrocarbon composition and the amount of salts and organic inhibitors, it is possible to determine the hydrate stability zone. Superimposing the pipeline pressure and temperature profiles will give the hydrate safety margin. The red line shows that the system is inside the hydrate stability zone. The amber line indicates that the system is outside the hydrate stability zone; however, there is no safety margin. The green line indicates the desirable conditions. If the hydrate stability zone is very far and to the left of pipeline conditions, it means that too much inhibitor is being injected.

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DETECTING EARLY SIGNS OF HYDRATE FORMATION It is believed that for many hydrocarbon systems the initial hydrate formation does not result in pipeline blockage. In fact, when the initial hydrate formation is not detected and, hence, addressed, further hydrate formation can occur and the resulting buildup of hydrates could cause pipeline blockage. Furthermore, it is known that structure II (sII) hydrates are the most stable hydrate structure in the majority of naturally occurring hydrocarbon systems. It is well-known that the composition of the gas trapped in the hydrate structure is different from that of the hydrocarbon phases. Gas hydrates prefer large and round molecules; hence, in sII-dominated systems, propane and isobutane are concentrated in the hydrate phase, reducing their concentration in the gas phase. Therefore, hydrate formation in the sII-dominated system will result in a reduction in the concentration of C3 and iC4 in the gas phase. The experiments conducted in this laboratory suggest that conversion of a minimum of 5 barrels of water per million standard cubic feet (mmscf) of gas could cause detectable changes in the gas composition against background compositional variations (i.e., noise).13 In general, the pressure and temperature conditions at the wellhead could be outside the hydrate stability zone; however, because of heat loss to the environment and/or Joule− Thompson (JT) effect, the system may enter the hydrate stability zone in subsea transfer lines, whereas the pressure and temperature conditions in the riser could be outside the hydrate stability zone (i.e., resulting in hydrate dissociation). This could result in a condition where there is no obvious sign of hydrate formation in the receiving facilities. In addition to monitoring the composition of produced gas, a change in the composition and the amount of gas released from aqueous phase could be an indication of hydrate formation in subsea pipelines. It is known that the amount of gas trapped in the hydrate structure could be as high as 15 mol %.

are used to determine the amount of inhibitor required in the aqueous phase to prevent gas hydrate formation; therefore, any loss to hydrocarbon phases could reduce the amount of inhibitor available in the aqueous phase. In general, the amount of inhibitor loss to hydrocarbon phases is estimated/calculated/ measured and added to the amount of inhibitor required in the aqueous phase. Finally, a safety margin is considered, and the inhibitor injection rate is calculated. Despite all of the above, hydrate formation happens and oil and gas pipelines are blocked. In real field application, there are various other factors that can affect the actual concentration of inhibitors in the aqueous phase, hence, the hydrate stability zone, including (1) changes in the inhibitor partition in the hydrocarbon phase(s) because of changes in the system conditions, (2) changes in the amount of water in the system because of changes in the amount of formation water production and/or system conditions (that can affect the amount of condensed water), (3) potential equipment malfunction, (4) human error, and (5) inhibitor purity/ specification. Another possibility is injection of too much inhibitor that could affect the project economy, in addition to potential environmental consequences. Therefore, the key point is determining the amount of thermodynamic inhibitors in actual pipeline systems. As a result of a joint industry project, this laboratory developed a robust technique for determining the amount of salt and thermodynamic inhibitors based on measuring electrical conductivity and acoustic velocity in an aqueous sample. These two readings together with the sample temperature are fed to a pretrained artificial neural network (ANN), which returns the amount of salt and chemical inhibitors. In fact, the technique determines the actual amount of inhibitors in pertaining pipeline conditions at the point of sampling; thus, there is no need for any assumption/estimate. 4054

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Furthermore, it is known that after hydrate dissociation there are remnants of hydrate structure in the aqueous phase. This will result in (1) an increase in the amount of gas released from aqueous phase and (2) a significant increase in the concentration of hydrate-forming components (e.g., C3 and iC4 in the case of sII hydrates) in the aqueous phase. Therefore, it might be possible to detect early signs of hydrate formation from monitoring the composition of gas in the pipeline or first-stage separator and/or the composition/ amount of the gas released in the first-stage water degasser. The latter technique could also be used for systems where the amount of water converted into hydrates is less than 5 barrels/ mmscf, assuming that some hydrate crystals are transferred by the fast-moving gas phase. The above techniques have been tested extensively under laboratory conditions. Although full field evaluation is required to examine the technique under real field conditions, recent evaluation of field data demonstrated applicability of the methodology. This laboratory is conducting further research and development on other early detection systems. It is believed that hydrate safety margin monitoring and hydrate early detection systems and, in particular, integration of the two techniques could massively improve reliability of hydrate prevention strategies, reducing the costs associated with avoiding gas hydrates as well as improving their environmental impact.

Figure 3. Predicted methane hydrate stability zone in the presence of distilled water and experimental pressure and temperature profiles during cooling, hydrate formation, heating and melting, and reformation of hydrates. As shown in the figure, after some degree of subcooling, the hydrates are formed. An exothermic reaction results in a slight increase in the system temperature and significant pressure drop to the hydrate stability zone (because as a result of the phase rule, there is only one degree of freedom). Increasing the system temperature to slightly higher than the methane hydrate stability zone results in hydrate dissociation and pressure increase. Before dissociating all hydrates, the system is cooled to re-enter the hydrate stability zone. As shown in the figure, the hydrates are formed again without any degree of subcooling. The data points are collected every 5 min.

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NEW TECHNIQUES FOR EVALUATING KHIS Hydrate formation is a crystallization process that consists of nucleation and growth. The general understanding is that KHIs interfere and delay hydrate formation and pipeline blockage even if the system conditions are inside the hydrate stability zone. There are several misconceptions with respect to KHIs: (1) The time delay (Δt) is inversely related to subcooling (ΔT, i.e., difference between system temperature and hydrate dissociation temperature at a given pressure); hence, indefinite inhibition is not possible with KHI. Therefore, KHIs do not work for shut-in conditions. (2) Pipelines with stratified flow cannot be protected by KHIs, because hydrates will form at the top of the pipeline, which will result in pipeline blockage. (3) If a hydrate crystal is introduced in a system being protected by KHIs, massive hydrate formation could occur. Furthermore, there are repeatability problems with KHI evaluation runs, even in one laboratory and using the same cell. Therefore, various protocols were developed using certain test facilities/loading/test procedures. Also, a wide range of subcoolings has been reported for KHIs, making their application very much system-specific. As a result, it was impossible to predict whether KHIs could be considered as an option for a development without extensive testing. There are several examples where a moderate subcooling could not be achieved for certain systems, whereas for other systems, KHIs could have provided twice or even 3 times subcooling. The objective of this discussion is to clarify some of the myths around KHI performance and provide guidelines on their evaluation and application. Figure 3 shows cooling and hydrate formation from methane and distilled water when the system reaches the required subcooling. In this case (i.e., pure methane), the system pressure drops to that of the methane hydrate stability zone upon hydrate formation (because there is no change in the hydrocarbon and free water phase compositions as a result of hydrate formation). Clearly, when the system temperature is increased to outside the methane

hydrate stability zone, hydrates start dissociating and the system pressure increases. Now, if the system is cooled again prior to complete dissociation of all hydrates, no subcooling is required for hydrate formation (because hydrate nuclei already exist) and the pressure will follow that of the methane hydrate phase boundary.14 Figure 4 shows the same experiment in the presence of 0.25% poly(N-vinylcaprolactam) (PVCap). As shown in the figure, the hydrate formation part is very much similar to the previous system; however, for hydrate dissociation, the system temperature should be much higher than the hydrate stability zone. Also, if the system temperature is reduced after partial dissociation of hydrates (i.e., returning just inside the hydrate stability zone), hydrates continue dissociation instead of formation, which was observed for the same system without KHIs. As shown in the figure, the system pressure does not reach the original pressure, indicating that some of the hydrates are left in the system. Within a joint industry project, an extensive test program was conducted. Some of the results are shown in Figure 5. As shown in the figure, various regions could be identified for a KHI, which are as follows: (1) Complete inhibition region (CIR) is where hydrate formation can be prevented indefinitely/very long time. This means that KHIs can protect systems under shut-in conditions if the subcooling is within CIR. Furthermore, as shown in Figure 4, existing hydrates could dissociate in CIR, which means KHIs could be considered for pipelines under stratified conditions. (2) Slow growth region (SGR) is where the amount of hydrates formed is a function of time and the induction time (Δt) depends upon the degree of subcooling (ΔT). This section can be further divided into very slow (VS) and slow (S) regions, as shown in the figure. In this region, the induction time could be a strong function of subcooling; hence, a small change in subcooling 4055

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presence of KHIs are more difficult to dissociate, because extra heat is required to desorb KHI polymers from hydrate crystals. The above results are for methane−water systems, where structure I (sI) is the stable structure. Our investigations show that for systems where sII is the most stable structure the degree of subcooling will depend upon the position of the sI hydrate phase boundary because sI seems to be the hydrate structure that forms first in the presence of KHIs. This can explain the discrepancies observed in the performance KHIs in various fluid systems, in addition to some other reasons that are detailed in the study by Anderson et al.14 The technique has been successfully applied to evaluation commercial KHIs.15

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ADVANCES IN THERMODYNAMIC MODELING Thermodynamic modeling highly non-ideal solutions containing water−salts−alcohols/glycols could be very challenging, in particular for CO2-rich systems. A cubic plus association equation of state (EoS) approach has been used for modeling the above systems, which is detailed elsewhere.16 In this section, the application of the above approach to CO2-rich systems has been discussed, considering the growing interest in such systems for CO2 capture, transport, and storage (CCS).7 Water condensation in CO2-rich systems could result in corrosion and ice/hydrate formation. Dehydration is currently the most common technique in preventing water condensation and associated risks. CO2 is a near-critical fluid under ambient conditions; hence, small changes in the system pressure and temperature could result in significant changes in its properties and phase behavior. Furthermore, water solubility7,17−19 in gaseous CO2 decreases with an increase in the system pressure until the bubble point, where it sharply increases when CO2 becomes liquid, as shown in Figure 6. This could have a

Figure 4. Methane hydrate phase boundary in the presence of distilled water and experimental pressure and temperature profiles during cooling, hydrate formation, heating and melting, and cooling in the presence of 0.25 mass % PVCap in the aqueous phase. As shown in the figure, the initial cooling and hydrate formation are very much similar to those of distilled water (i.e., Figure 3). However, for hydrate dissociation, the system temperature needs to be increased 4−5 °C outside the hydrate stability zone. Furthermore, upon cooling and reentering the hydrate stability zone, most of the remaining hydrates dissociate (instead of forming, as observed in Figure 3). Upon slow cooling (data points taken every 5 min), the amount of hydrates increases when the system is some 2.5 °C inside the hydrate stability zone. The rate of hydrate formation increases as the system is cooled further, and finally, the system fails at 5 °C inside the hydrate stability zone. Various regions are identified in the figure after an extensive series of tests.

Figure 5. Experimental crystal growth inhibition regions for 1.0 mass % PVCap with methane. CIR is where hydrate formation can be prevented indefinitely. SGR is where the amount of hydrates formed is a function of time and the induction time (Δt) depends upon the degree of subcooling (ΔT). This section can be further divided into very slow (VS) and slow (S) regions, as shown in the figure. RFR is where KHIs can no longer prevent or delay hydrate formation. SDR is where hydrate dissociation is very slow and the rate of dissociation depends upon how much the system is outside the hydrate stability zone.

Figure 6. Water content in the vapor and liquid phases of the carbon dioxide−water system at approximately 15 °C (solid lines, predictions by Chapoy et al.;7 red ●, data from Chapoy et al.;7 blue ◆, data from Valtz et al.17 at 15.11 °C; yellow ▲, data from King et al.18 at 15 °C; green ◆, data from Song and Kobayashi19 at 2.7 and 3 °C; and cyan ●, carbon dioxide/hydrogen−water system).

significant effect on the hydrate stability zone of pure CO2 systems when there is no free water, as shown in Figure 7. CO2 captured from power plants could have a wide range of impurities.20 The investigation conducted in this laboratory shows that small amounts of impurities could have a significant effect on the phase behavior and properties of CO2-rich systems. As an example, Figure 8 shows the effect of 2 mol % H2 on the phase behavior of CO2-rich systems and the fact that 2% H2 may increase the system bubble point, resulting in one of the operating conditions falling inside the hydrate stability

could change the induction time significantly. (3) Rapid formation region (RFR) is where KHIs can no longer prevent or delay hydrate formation. (4) Slow dissociation region (SDR) is where hydrate dissociation is very slow and the rate of dissociation depends upon how much the system is outside the hydrate stability zone. This means that hydrates formed in the 4056

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AUTHOR INFORMATION

Corresponding Author

*Telephone: +44-131-451-3672. Fax: +44-131-451-3127. Email: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank sponsors of various Joint Industry Projects at the Centre for Gas Hydrate Research, Heriot-Watt University, and Hydrafact for their support, in particular (in alphabetical order), Baker Hughes, BP, Champion Technologies, Chevron, Clariant Oil Services, DONG Energy, NIGC, OMV, Petrobras, Petronas, Progressive Energy, Shell, Statoil, and Total.

Figure 7. Pure CO2 hydrate stability zone (solid red lines) for the 250 ppm system (H, hydrate; VCO2, rich CO2 vapor phase; LCO2, rich CO2 liquid phase; and I, ice). The gray dotted lines represent the hydrate/ ice stability zone in saturated conditions (i.e., in the presence of free water). As shown in the figure, the conditions in the pipeline and after the choke are inside the hydrate stability zone for the water-saturated system but outside the hydrate stability zone for the 250 ppm water content system. Yellow ▲ represent operating conditions.

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REFERENCES

(1) Sloan, E. D.; Koh, C. A. Clathrate Hydrates of Natural Gases, 3rd ed.; CRC Press (Taylor and Francis Group): Boca Raton, FL, 2008. (2) Hammerschmidt, E. Formation of gas hydrates in natural gas transmission lines. Ind. Eng. Chem. 1934, 26 (8), 851−855. (3) Frostman, L. Anti-agglomerant hydrate inhibitors for prevention of hydrate plugs in deepwater systems. Proceedings of the Society of Petroleum Engineers (SPE) Annual Technical Conference and Exhibition; Dallas, TX, Oct 1−4, 2000; SPE 63122. (4) Mokhatab, S.; Wilkens, R.; Leontaritis, K. A review of strategies for solving gas-hydrate problems in subsea pipelines. Energy Sources, Part A 2007, 29 (1), 39−45. (5) Alapati, R.; Lee, J.; Beard, D. Two field studies demonstrate that new LDHI chemistry is effective at high water cuts without impacting oil/water quality. Proceedings of the Offshore Technology Conference; Houston, TX, May 5−8, 2008; OTC 19505. (6) Kelland, M. A. History of the development of low dosage hydrate inhibitors. Energy Fuels 2006, 20 (3), 825−847. (7) Chapoy, A.; Burgass, R.; Tohidi, B.; Austell, J. M.; Eickhoff, C. Effect of common impurities on the phase behaviour of carbon dioxide rich systems: Minimizing the risk of hydrate formation and two-phase flow. Proceedings of the Society of Petroleum Engineers (SPE) Offshore Europe Oil and Gas Conference and Exhibition; Aberdeen, U.K., Sept 8− 11, 2009; SPE 123778. (8) Yang, J.; Chapoy, A.; Mazloum, S.; Tohidi, B. A novel technique for monitoring hydrate safety margin. Proceedings of the Society of Petroleum Engineers (SPE) Annual Conference and Exhibition; Vienna, Austria, May 23−26, 2011; SPE 143619. (9) Bonyad, H.; Zare, M.; Mosayyebi, M. R.; Mazloum, S.; Tohidi, B. Field evaluation of a hydrate inhibition monitoring system. Proceedings of the 10th Offshore Mediterranean Conference (OMC); Ravenna, Italy, March 23−25, 2011. (10) Macpherson, C.; Glenat, P.; Mazloum, S.; Young, I. Successful deployment of a novel hydrate inhibition monitoring system in a North Sea gas field. Proceedings of the 23rd International Oil Field Chemistry Symposium; Geilo, Norway, March 18−21, 2012. (11) Lavallie, O.; Al-Ansari, A.; O’Neil, S.; Chazelas, O.; Glénat, P.; Tohidi, B. Successful field application of an inhibitor concentration detection system in optimising the kinetic hydrate inhibitor (KHI) injection rates and reducing the risks associated with hydrate blockage. Proceedings of the International Petroleum Technology Conference; Doha, Qatar, Dec 7−9, 2009; IPTC 13765. (12) Mazloum, S.; Chapoy, A.; Yang, J.; Tohidi, B. Online monitoring of hydrate safety margin. Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011); Edinburgh, U.K., July 17− 21, 2011. (13) Mazloum, S.; Chapoy, A.; Yang, J.; Tohidi, B. Developing a robust hydrate early warning system. Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011); Edinburgh, U.K., July 17− 21, 2011.

Figure 8. Hydrate stability zone (solid red lines) for the binary 98% CO2 − 2% H2 mixture in the presence of 250 ppm water (H, hydrate; I, ice; VC, rich CO2 vapor phase; and LC, rich CO2 liquid phase). The gray dotted lines represent the hydrate/ice stability zone in saturated conditions (i.e., in the presence of free water). Purple ▲ represent operating conditions.

zone. Therefore, to avoid hydrate formation, the operator has to either reduce the water content or increase the system pressure to above the bubble point to avoid hydrate risk.

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CONCLUSION Although no major breakthrough, the research and development in the past decade or so have indentified several new solutions that can reduce the risks associated with hydrate blockage. The proposed/developed techniques for monitoring hydrate safety margin and detecting early signs of hydrate formation can improve reliability of hydrate prevention strategies and help in automation. The latest findings on the mechanisms involved in kinetic hydrate inhibition and the techniques developed for evaluating KHIs could potentially eliminate the nonrepeatability problem, while improving confidence in the application of these inhibitors. The latest improvements in thermodynamic modeling have paved the way for more accurate modeling of some of the challenging conditions, such as high inhibitor concentrations, low water content systems, and/or high CO2/H2S content systems. 4057

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(14) Anderson, R.; Mozaffar, H.; Tohidi, B. Development of a crystal growth inhibition based method for the evaluation of kinetic hydrate inhibitors. Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011); Edinburgh, U.K., July 17−21, 2011. (15) Glénat, P.; Anderson, R.; Mozaffar, H.; Tohidi, B. Application of a new crystal growth inhibition based KHI evaluation method to commercial formulation assessment. Proceedings of the 7th International Conference on Gas Hydrates (ICGH 2011); Edinburgh, U.K., July 17− 21, 2011. (16) Haghighi, H.; Chapoy, A.; Tohidi, B. Modelling phase equilibria of complicated systems containing petroleum reservoir fluids. Proceedings of the 2009 Society of Petroleum Engineers (SPE) Offshore Europe Oil and Gas Conference and Exhibition; Aberdeen, U.K., Sept 8− 11, 2009; SPE 123170. (17) Valtz, A.; Chapoy, A.; Coquelet, C.; Paricaud, P.; Richon, D. Vapour−liquid equilibria in the carbon dioxide−water system, measurement and modelling from 278.2 to 318.2 K. Fluid Phase Equilib. 2004, 226, 333−344. (18) King, M. B.; Mubarak, A.; Kim, J. D.; Bott, T. R. The mutual solubilites of water with supercritical and liquid carbon dioxide. J. Supercrit. Fluids 1992, 5, 296−302. (19) Song, K. Y.; Kobayashi, R. Water content of CO2 in equilibrium with liquid water and/or hydrates. SPE Form. Eval. 1987, 2, 500−508. (20) de Vissera, E.; Hendriksa, C.; Barriob, M.; Mølnvikb, M. J.; de Koeijerc, G; Liljemarkd, S.; Le Galloe, Y. Dynamis CO2 quality recommendations. Int. J. Greenhouse Gas Control 2008, 2 (4), 478− 484.

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