Sour Gas Hydrate Formation Phase Behavior

A phase envelope with hydrate and water dew point curves is an excellent tool to find what phase water is in at operating conditions, during start-up, during shut-down and during upsets. In the November 2007 Tip of the Month (TOTM), we discussed the phase behavior of water-sour natural gas mixtures. In this tip, we will extend our study on the sour natural gas hydrate formation phase behavior. Specifically, we will study the impact of H₂S and CO₂ on the formation of hydrate in natural gas.

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. At equilibrium, the chemical potential of water in the hydrate phase is equal to that in each of the other coexisting phases. Parrish and Prausnitz [1] developed a thermodynamic model to describe this phenomenon, and later, the model was improved by Holder et al. [2]. These methods are suitable for calculations using a computer with equations of state. The details of hand calculation methods can be found in Chapter 6 of Volume 1 [3] of “Gas Conditioning and Processing” and Chapter 20 of GPSA DATA BOOK [4]. In this work we will use the Soave-Redlich-Kwong (SRK EoS) [5] in ProMax [6] software.

The compositions of the gas mixture studied in this study are shown in Table 1.

Table 1. Water-saturated compositions of gas mixtures studied

Figure 1 presents the calculated hydrate formation curve (solid curve) and the dew point portion of the phase envelope of a sweet natural gas (solid curve with the square). Figure 1 also presents the dew point and hydrate formation curves for the same gas mixture containing 10 and 20 mole  % CO₂. Figure 1 indicates that as the CO₂ mole % increases from 0 to 20 mole %, the hydrate formation curves shift slightly to the left, depressing the hydrate formation temperature. 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/prevented. This figure also indicates, as CO₂ mole % increases, the cricondenbar decreases and the phase envelope shrinks.

Figure 1. The impact of CO₂ on the hydrocarbon dew point and hydrate formation curve.

Similarly, Figure 2 presents the calculated hydrate formation curve (solid curve) and the dew point portion of phase envelope for the same sweet natural gas (solid curve with the square). Figure 2 also presents the dew point and hydrate formation curves for the same gas mixture containing 10 and 20 mole  % H₂S. Figure 2 indicates that as the H₂S mole % increases from 0 to 20 mole %, the hydrate formation curves shift considerably to the right, promoting the hydrate formation temperature. This is opposite to the effect of CO₂ and it is more pronounced. From an operational point of view, this is undesirable because H₂S expands the hydrate formation region to the right. Note that the points to the right and below of the hydrate curve represent the hydrate-free region. Figure 2 also indicates, as H₂S mole % increases, the cricondenbar decreases and the phase envelope shrinks. The shrinkage of the phase envelope is less than that of CO₂.

Figure 2. The impact of H₂S on the hydrocarbon dew point and hydrate formation curve.

Figure 3 presents the calculated hydrate formation curves for a sweet gas, a sour gas with 20 mole % CO₂ and a sour gas with 20 mole % H₂S. This figure clearly indicates that the impact of H₂S is much bigger than the CO₂ impact; CO₂ depresses (shifts to the left) the hydrate formation condition slightly but H₂S promotes hydrate formation considerably. As an example, at 1000 psia (6900 kPa), CO₂ reduces hydrate formation temperature for this gas by about 5.5˚F (3˚C) while, H₂S increase hydrate formation temperature by about 20˚F (11.1˚C).

Conclusions:

The presence of CO₂ and H₂S in natural gas has an opposite impact on the hydrate formation condition. While the impact of CO₂ is small, H₂S has considerable impact on the hydrate formation condition. CO₂ depresses hydrate formation (acts as hydrate inhibitor and shifts the hydrate curve to the left) while H₂S shifts the hydrate curve to the right, promotes hydrate formation conditions, and may cause severe operational problems.

To learn more about similar cases and how to minimize operational problems, we suggest attending our G40 (Process/Facility Fundamentals), G4 (Gas Conditioning and Processing), P81 (CO₂ Surface Facilities), and PF4 (Oil Production and Processing Facilities) courses.

John M. Campbell Consulting (JMCC) offers consulting expertise on this subject and many others. For more information about the services JMCC provides, visit our website at www.jmcampbellconsulting.com, or email us at consulting@jmcampbell.com.

By: Dr. Mahmood Moshfeghian

Figure 3. The opposite impact of CO₂ and H₂S on the hydrate formation curve.

Reference:

1. Campbell, J.M., “Gas conditioning and Processing, Vol 1: The Basic Principles”, 8^th Edition, Edited by R.A. Hubbard, John M. Campbell & Company, Norman, USA, 2001.
2. Parrish, W.R., and  J.M. Prausnitz, “Dissociation pressures of gas hydrates formed by gas mixtures,” Ind. Eng. Chem. Proc. Dev. 11: 26, 1972.
3. 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.
4. 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.

6. ProMax 3.2, Bryan Research and Engineering, Inc, Bryan, Texas, 2012.