What is the Impact of Light Hydrocarbons on the Natural Gas Hydrate Formation Conditions?

The December 2012 [1] and January 2016 [2] Tips of the Month (TOTM) discussed the hydrate phase behavior of natural gas mixtures containing high content hydrogen sulfide, carbon dioxide, or nitrogen. Specifically, it showed nitrogen and carbon dioxide inhibit the hydrate formation slightly while hydrogen sulfide enhances hydrate formation considerably. This tip will extend the previous studies on the natural gas hydrate formation phase behavior. Specifically, it will study the impact of light hydrocarbons on the formation of hydrate in a natural gas mixture.

The hydrate formation temperature of a gas depends on the system pressure and composition. There are several methods of calculating the hydrate formation conditions of natural gases [3-6]. References [3-4] present rigorous methods while [5-6] present the shortcut methods suitable for hand calculations. This study uses a rigorous method using the Soave-Redlich-Kwong (SRK) equation of state [7] in ProMax [8] software.

Table 1 presents the compositions (mol %) of the gas mixtures studied. Notice that for non-hydrocarbons (gases B, C, and D) about 18 mol % of methane is replaced with about 20 mol % of either nitrogen, carbon dioxide or hydrogen sulfide. These compositions are for a gas stream leaving a separator at 100 °F and 1000 psia (37.8 °C and 6900 kPaa) saturated with water.

Table 1. Water-saturated compositions (mol %) of gas mixtures studied

Figure 1 presents the calculated hydrate formation and the dew point portion of the phase envelope (continuous curves) of a sweet natural gas (gas E of Table 1) containing 0 mol % C₂H₆. Figure 1 also presents the dew point and hydrate formation (broken curves) for gas F of Table 1 containing 17.8 mol % C₂H₆.

Figure 1. The impact of C₂H₆ on the hydrocarbon dew point and hydrate formation curves

Figure 1 indicates that the presence of 17.8 mol % C₂H₆ has a negligible effect on the hydrate formation curve. Note that the points to the left and above the hydrate curves represent the hydrate formation region. From an operational point of view, this region should be avoided. This figure also indicates that the presence of C₂H₆ decreases the cricondenbar pressure and the cricondentherm temperature; therefore, the two-phase (gas + liquid) region within the envelope shrinks.

Figure 2 presents the calculated hydrate formation and the dew point portion of the phase envelope (continuous curves) of a sweet natural gas (gas G of Table 1) containing 0 mol % C₃H₈. Figure 2 also presents the dew point and hydrate formation curves (broken curves) for gas H of Table 1 containing 12.7 mol % C₃H₈. Figure 2 indicates that the presence of 12.7 mol % C₃H₈ shifts the hydrate formation curve to the right promoting the hydrate formation condition. This figure also indicates that the presence of C₃H₈ decreases the cricondenbar pressure while having little effect on the cricondentherm temperature; the two-phase (gas + liquid) region within the envelope shrinks.

Similarly, Figure 3 presents the impact of 12.7 mol % iC₄H₁₀ on the dew point and hydrate formation curves for gases I and J of Table 1. This figure indicates that iC₄H₁₀ like C₃H₈ is a hydrate promotor and shifts the hydrate curve to the right.

Figure 2. The impact of C₃H₈ on the hydrocarbon dew point and hydrate formation curves

Figure 3. The impact of iC₄H₁₀ on the hydrocarbon dew point and hydrate formation curves

Similarly, Figure 4 presents the impact of 11.4 mol % nC₄H₁₀ on the dew point and hydrate formation curves for gases K and L of Table 1. This figure indicates that contrary to iC₄H₁₀, nC₄H₁₀ is a hydrate inhibitor and shifts the hydrate curve to the left. Both iC₄H₁₀ and nC₄H₁₀ lower the cricondentherm temperature and increase the cricondenbar pressure.

Figure 4. The impact of nC₄H₁₀ on the hydrocarbon dew point and hydrate formation curves.

Figure 5 presents a summary of the calculated hydrate formation curves for sweet gas A of Table 1 (Continuous curve), and gases B (20 mol % H₂S), gas C (20 mol % CO₂), gas D (20 mol % N₂), gas F (17.8 mol % C₂H₆), gas H (12.7 mol % C₃H₈), gas J (12.7 mol % iC₄H₁₀), gas L (11.4 mol % nC₄H₁₀) (broken curves). For the cases studied, this figure clearly indicates that the impact of N₂ is much less than of H₂S and slightly less than of CO₂. Nitrogen, carbon dioxide, and nC₄H₁₀, depress the hydrate formation condition (shift the hydrate curves to the left). Between these three components, nC₄H₁₀ has the larger depression effect even though its mol % is smaller. While C₂H₆ has the same effect as CH₄ on the hydrate formation condition (no shift on the hydrate formation curve), C₃H₈, iC₄H₁₀, and H₂S promotes hydrate formation condition. Among these hydrate promotors, H₂S has the largest contribution even for only 10 mol %. Note that “Sweet Gas” refers to gas A in Table 1.

Figure 5. The impact of nitrogen, acid gases and light hydrocarbon gases on the sweet gas hydrate formation curve.

Conclusions:

All of the molecules studied in this tip are hydrate formers. Some enhances hydrate formation of methane and some lowers hydrate formation of methane. Katz and co-workers [9] developed a set of vapor-solid equilibrium constants (K_v-s) values for hydrate prediction. In the Katz method as described on page 161 of Chapter 6 of reference [7] “nitrogen is a hydrate former, and it is likely that some nitrogen may end up in the hydrate lattice in typical natural gas production systems. However, it is not a factor in determining hydrate formation conditions unless you are working with mixtures of nitrogen and methane which are sometimes found in coalbed methane production. In these cases the N₂-CH₄ mixture will have a lower hydrate formation temperature than pure methane. As a practical matter using K_v-s = (infinity) for nitrogen gives satisfactory results for typical natural gas mixtures”.

This study has shown that while C₂H₆ has the same effect as CH₄; N₂, CO₂, nC₄H₁₀ have the opposite effect on hydrate formation of sweet gas compared to light hydrocarbon gases of C₃H₈, iC₄H₁₀, and H₂S. While the impact of N₂, CO₂, and nC₄H₁₀ is small in the same direction, C₃H₈, iC₄H₁₀, and H₂S have considerable impact on the hydrate formation condition. For the composition and condition (Table 1) studied, N₂, nC₄H₁₀, and CO₂ slightly depresses hydrate formation (shifts the hydrate curve to the left) while C₃H₈, iC₄H₁₀, and H₂S shift the hydrate curve to the right considerably, promoting hydrate formation conditions, and may cause severe operational problems. Table 1 also indicates that the predicted water content of sweet gases (Gases A, and D through L) is practically independent of gas composition. These results are not in complete agreement with the curves shown in the Trekell-Campbell method [5] which show the contribution of these components to the pure methane hydrate formation curve.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G4 (Gas Conditioning and Processing), G5 (Advanced Applications in Gas Processing), P81 (CO₂ Surface Facilities), and PF4 (Oil Production and Processing Facilities), courses.

PetroSkills offers consulting expertise on this subject and many others. For more information about these services, visit our website at http://petroskills.com/consulting, or email us at consulting@PetroSkills.com.

By: Dr. Mahmood Moshfeghian

Reference:

1. Moshfeghian, M., http://www.jmcampbell.com/tip-of-the-month/2012/12/sour-gas-hydrate-formation-phase-behavior/
2. Moshfeghian, M., http://www.jmcampbell.com/tip-of-the-month/2016/01/what-is-the-impact-of-nitrogen-on-the-natural-gas-hydrate-formation-conditions/
3. Parrish, W.R., and J.M. Prausnitz, “Dissociation pressures of gas hydrates formed by gas mixtures,” Ind. Eng. Chem. Proc. Dev. 11: 26, 1972.
4. Holder, G. D., Gorbin, G. and Papadopoulo, K.D, “Thermodynamic and molecular properties of gas hydrates from mixtures containing methane. argon, and krypton,” Ind. Eng. Chem. Fund. 19(3): 282, 1980.
5. Campbell, J.M., Gas Conditioning and Processing, Volume 1: The Basic Principles, 9^th Edition, 2^nd Printing, Editors Hubbard, R. and Snow–McGregor, K., Campbell Petroleum Series, Norman, Oklahoma, 2014.
6. Gas Processors Suppliers Association; “ENGINEERING DATA BOOK” 13^th Edition – FPS; Tulsa, Oklahoma, USA, 2012.

1. G. Soave, Chem. Eng. Sci. 27, 1197-1203, 1972.

1. ProMax 3.2, Bryan Research and Engineering, Inc, Bryan, Texas, 2015.
2. Carson, D. B. and D. L. Katz, Trans. AIME, Vol. 146, p. 150, 1942.