Natural gas hydrate temperature

This graphical method was developed for field operations personnel. It is designed for sour natural gas at 100 to 4,000 psia up to 50% H2S or sweet gas with C3 up to 10%. 

Example. Calculate the hydrate temperature for the following conditions  

Enter at the left at 500 psia, go to the right to 10% HjS, and drop down to 0.7 gravity. This hits just below the sloped line near 65°F. Parallel this line down to about 65.5°F. 

correct for C3 content. Enter the small adjustment graph at the left at 10% H2S, go to the right to 0.5% C3, 

Baillie, C. and Wichert, B., Chart Gives Flydrate Formation Temperature for Natural Gas, Oil and Gas Journal, April 6, 1987, p. 37. 

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Of special interest in recent years has been the analysis of natural gas hydrates that form in marine sediments and polar rocks when saline pore waters are saturated with gas at high pressure and low temperature. Large and 5D-variations of hydrate bound methane, summarized by Kvenvolden (1995) and Milkov (2005), suggest that gas hydrates represent complex mixtures of gases of both microbial and thermogenic origin. The proportions of both gas types can vary significantly even between proximal sites. 

In the mid-1930s Hammerschmidt studied the 1927 hydrate review of Schroeder (D.L. Katz, Personal Communication, November 14, 1983) to determine that natural gas hydrates were blocking gas transmission lines, frequently at temperatures above the ice point. This discovery was pivotal in causing a more pragmatic interest in gas hydrates and shortly thereafter led to the regulation of the water content in natural gas pipelines. 

FIGURE 3.10 Hydrate labile cluster growth mechanism imposed on a pressure-temperature trace. (Reproduced from Christiansen, R.L., Sloan, E.D., in Proc. First International Conference on Natural Gas Hydrates (1994) New York Academy of Sciences. With permission.)... 

The enthalpy of hydrate formation of simple natural gas hydrate formers (from gas and water or ice) is given in Table 4.7 taken from the dissertation of Kamath (1984). Note that each component has two temperature regions, above and below the ice point, with a A77 difference related by the heat of fusion at the ice point. 

In a thorough review of calorimetric studies of clathrates and inclusion compounds, Parsonage and Staveley (1984) presented no direct calorimetric methods used for natural gas hydrate measurements. Instead, the heat of dissociation has been indirectly determined via the Clapeyron equation by differentiation of three-phase equilibrium pressure-temperature data. This technique is presented in detail in Section 4.6.1. 

There are four requirements for generation of natural gas hydrates (1) low temperature, (2) high pressure, (3) the availability of methane or other small nonpolar molecules, and (4) the availability of water. Without any one of these four criteria, hydrates will not be stable. As indicated in both the previous section and in Section 7.4.3, the third criteria for hydrate stability—namely methane availability—is the most critical issue controlling the occurrence of natural gas hydrates. Water is ubiquitous in nature so it seldom limits hydrate formation. However, the first two criteria are considered here as an initial means of determining the extent of a hydrated reservoir. 

The first systematic phase equilibrium study of hydrates was carried out at the US Bureau of Mines by Deaton and Frost for a number of natural gas hydrate systems. Although the separation methods were somewhat crude (e.g., a distinction could not be made between butane isomers), their hydrate formation pressure and temperature data continue to be foundations for prediction comparisons. 

Figure 1 The common hydrate cages and structural families, giving the unit cell compositions, lattice symmetry and parameters. The guests indicated are those typically found in natural gas hydrates of each structure. The guests in the last column usually are a minor component and may be present in any of the structures since they fit in the small D and D cavities. The actual hydrate stnictiire formed depends on the partial pressure of each gas component and the pressure and temperature.

Figure 3 Different methods of hydrate formation (1-5) each can give a distinct perspective on certain aspects of hydrate formation l-ice + gas at T< 273K 2- ice with the temperature ramped above T = 273K 3 - amorphous ice +gas at T < 13 OK 4 and 5, either quiescent or with agitation are usually used for phase equilibrium studies and the effect of inhibitors. Simulation of natural gas hydrate requires the addition of sediment at various levels of water-sediment content.

Gas hydrate forms wherever appropriate physical conditions exist—moderately low temperature and moderately high pressure—and the materials are present—gas near saturation and water. These conditions are found in the deep sea commonly at water depths greater than about 500 m or somewhat shallower depths (about 300 m) in the Arctic, where bottom-water temperature is colder. Gas hydrate also occurs beneath permafrost on land in arctic conditions, but, by far, most natural gas hydrate is stored in ocean floor deposits. A simplified phase diagram is shown in Fig. 2A, in which pressure has been converted to water depth in the ocean (thus, pressure increases downward in the diagram). The heavy line in Fig. 2A is the phase boundary, separating conditions in the temperature/pressure field where methane hydrate is stable to the left of the curve (hatched area) from conditions where it is not. In Fig. 2B, some typical conditions of pressure and temperature in the deep ocean were chosen to define the region where methane hydrate is stable. The phase boundary indicated is the same as in Fig. 2A, so methane hydrate is stable... 

The subject of gas hydrates has become highly topical in recent years (Sloan, 1997), particularly since the discovery of vast amounts of natural gas hydrates under ocean floor sediments at depths >500 m and in polar permafrost regions. Gas hydrates are clathrate compounds in which variable (non-stoichiometric) amounts of gas, e.g., methane, ethane and propane, are trapped within ice crystal lattice cages . The amount of entrapped gas increases with lowering temperature and increasing pressure. It has been estimated that world-wide the amount of methane trapped in gas hydrates is around 2 x 10 m at STP, which is roughly equivalent to twice the mass of carbon in all conventional... 

Seo et al. (Seo, et al., 2009) [3] studied composition and structure of natural gas hydrates using C NMR spectroscope. In their work, composition of the gas retrieved from hydrate at different formation temperatures showed that the concentration of methane was much lower than the feed composition and the concentration of heavier components were increased significantly. In this work, the compositional changes in the gas phase have been investigated and used to detect the presence of small amounts of hydrates in the system. 

StiU another source of methane is the gas hydrate. At high pressure, methane forms a clathrate (cage) complex with water which is stable at temperatures below 20°C and at pressures greater than 20 atm. This natural gas hydrate is present on the ocean floor, in the sediment below the seafloor, as well as in the cold permafrost of the Arctic. 

The average error of this simplified method is about 3°C and can reach 5°C. Table 4.22 shows an application of this method calculating the temperature of hydrate formation of a refinery gas at 14 bar. Table 4.23 gives an example applied to natural gas at 80 bar. Note that the presence of H2S increases the hydrate formation temperature. 

Table 4.23 Example calculation of the hydrate formation temperature for a natural gas at 80 bar abs. Result = 29.1 "C. ...

Methanol is frequently used to inhibit hydrate formation in natural gas so we have included information on the effects of methanol on liquid phase equilibria. Shariat, Moshfeghian, and Erbar have used a relatively new equation of state and extensive caleulations to produce interesting results on the effeet of methanol. Their starting assumptions are the gas composition in Table 2, the pipeline pressure/temperature profile in Table 3 and methanol concentrations sufficient to produce a 24°F hydrate-formation-temperature depression. Resulting phase concentrations are shown in Tables 4, 5, and 6. Methanol effects on CO2 and hydrocarbon solubility in liquid water are shown in Figures 3 and 4. 

This chapter discusses the procedures used to calculate the temperature at which hydrates will form for a given pressure (or the pressure at which hydrates will form for a given temperature), the amount of dehydration required to assure that water vapor does not condense from a natural gas stream, and the amount of chemical inhibitor that must be added to lower the hydrate formation temperature. It also discusses the temperature drop that occurs as gas is expanded across a choke. This latter calculation is vital to the calculation of whether hydrates will form in a given stream. 

Moisture must be removed from natural gas to reduce corrosion problems and to prevent hydrate formation. Hydrates are solid white compounds formed from a physical-chemical reaction between hydrocarbons and water under the high pressures and low temperatures used to transport natural gas via pipeline. Hydrates reduce pipeline efficiency. 

The parameters A, B, and C are dependent on the particular nature of the gas. Katz developed a simple method for gas mixtures that takes the composition of the gas into account [942,1086]. Furthermore, a graphic method is available that permits the estimation of the hydrate-forming temperatures at pressures for natural gas containing up to 50% hydrogen sulfide [129]. 

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