Chemical Inhibitor Injection Process

The third method is chemical inhibition, a concept similar to the chemical means presently used to inhibit the formation of water ice. This method seeks to displace the natural gas hydrate equilibrium condition beyond the hydrate stability zone’s thermodynamic conditions through injection of a liquid inhibitor chemical adja­cent to the hydrate. The chemical inhibitor injection method is also expensive, although less so than the thermal stimulation method, owing to the cost of the chemicals and the fact that it also requires good porosity. Figure 5.3 shows gas production by the chemical inhibitor injection process.

In the inhibitor injection process, an inhibitor such as methanol is injected into the gas hydrate zone. Chemical inhibitors shift the pressure-temperature equilib­rium so that the hydrates are no longer stable at the in situ pressure-temperature condition, and hydrate dissociates at the contacted surface (Desa 2001).


Fig. 5.3 Gas production by the chemical inhibitor injection process

An earlier work (Li et al. 2007) investigated the behavior of gas production from methane hydrate in porous sediment by injecting ethylene glycol solutions of different concentrations and at different injection rates in a one-dimensional ex­perimental apparatus. The results suggest that the gas production process can be divided into four stages: (1) the initial injection, (2) the dilution of ethylene glycol, (3) the hydrate dissociation, and (4) gas output. Nevertheless, the water production rate stays nearly constant during the whole production process. The production efficiency is affected by both the ethylene glycol concentration and the ethylene glycol injection rate, and it reaches a maximum for an ethylene glycol concentra­tion of 60 wt% (Li et al. 2007).

There are two approaches based on chemical concepts:

1. Chemical substitution: A very promising approach is the substitution of meth­ane for carbon dioxide, thus recovering methane while sequestering carbon di­oxide at the same time. The carbon dioxide can be brought into contact with the methane hydrate in the gas phase, in the liquid phase, or potentially dissolved in the circulating pore water (Ota et al. 2005a; Park et al. 2006). Raman spec­troscopy, NMR, and MRI data provide insightful information about the evolu­tion of the substitution (Graue et al. 2006; Gupta et al. 2005; Ota et al. 2005a, b; Sakamoto et al. 2005; Yoon et al. 2004). The optimal pressure – temperature operating conditions and underlying phenomena are reviewed in this chapter.

2. Chemical injection: Methanol, ethylene glycol, nitrogen, and salt brines are inhibitors that depress equilibrium conditions, so their injection prompts hy­drate dissolution and methane production; their effect is intimately coupled with the imposed temperature difference (Chatterji and Griffith 1998; Graue et al. 2006; Haneda et al. 2005; Kamath et al. 1991; Kawamura et al. 2005; Os – tergaard et al. 2005; Ota et al. 2005b; Sira et al. 1990; Sung et al. 2002, 2003; Yoon et al. 2004). Two solutions can be injected so that their exothermic reac­tion destabilizes the methane hydrate, liberating methane, and hindering its ref­ormation by altering the fluid chemistry and lowering the phase transformation boundary (Chatterji and Griffith 1998). There is some evidence that nitrogen gas combined with heating is more effective than heating alone (Sakamoto et al. 2005).

Common inhibitors can be alcohols (methanol), glycols (ethylene glycol), and ionic salts. Several types of inhibitors have been tested with positive results, but it has been determined that glycols and alcohols are the most successful ones. The principle by which alcohols, glycols, and salts inhibit hydrates is the same. How­ever, salts have some corrosion problems, and owing to low vapor pressures, they cannot vaporize. In the model reviewed here, methanol and ethylene glycol are examined and compared in many ways, such as chemical structure, physical prop­erties, cost analysis, safety concentration limits, environmental considerations, and dehydration capacities.

Besides temperature and pressure conditions, the composition and the neces­sary amount of inhibitor must be determined. The inhibitor must be at or below its water dew point (i. e., must be water-saturated). In addition, dehydration can be used as an alternative. To find the amount of inhibitor needed to produce a unit amount of methane, first the amount of temperature depression and then the disso­ciation rate with respect to the weight percent concentration of inhibitors are cal­culated. Inhibition effects depend on both temperature and pressure, but pressure only slightly affects inhibition of hydrates so it is neglected in the modeling of inhibition. Again, it is assumed that there is continuous inhibitor injection to the system (Lederhos et al. 1996). Many aspects need to be considered during injec­tion of inhibitors into gas hydrates, such as the shift in the equilibrium curve, the dissociation rate, and the properties of inhibitors.

The technology used with an ethylene glycol inhibitor results in lower cost, sa­fer concentration limits, and a more environmentally attractive alternative to me­thanol for hydrate prevention in offshore gas lines. Ethylene glycol is recovered with a higher efficiency than methanol. Therefore, without recovery facilities, the large makeup volumes of methanol required to inhibit the high volume of gas would represent an extremely high operating cost. The unit prices of methanol and ethylene glycol are $ 0.84 and $ 4.75 per gallon, respectively. At first sight, it may seem that methanol used as an inhibitor costs less, but the recovery and recycling costs, which are operating costs, exceed the lower unit price of methanol. Fur­thermore, methanol poses greater safety risks in handling and storage than ethyl­ene glycol. The flash points of methanol and ethylene glycol are 284 and 384 K, respectively, so methanol can be easily ignited.

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