Formation condition data for methane hydrate in ammonia + water and ammonia + water + tetrahydrofunan (THF) systems are very important for the process development and the determination of operation condition for recycling the vent gas of ammonia synthesis using hydrates. This paper focused on the formation conditions of methane hydrate in the presence of NH3 + H2O and NH3 + H2O + THF system. Equilibrium data of methane hydrate in the temperature, pressure and concentration ranges from 277 to 291 K, 0 to 8 MPa, 1 to 5 % ammonia, were obtained. The experimental results indicate that ammonia has an inhibitive effect on hydrate formation. The higher the concentration of ammonia is, the higher the formation pressure for methane hydrate will be.

In this paper, the effect of additives on COB2B hydrate formation is investigated in a high-pressure test cell surrounded by a thermostated coolant bath. An agitator is configured inside the cell. The characteristics of COB2B gas hydrate formation with additives SDS, THF and mixture of both were discussed. It was found that, in a quiescent system with single SDS，hydrate could form rapidly and the induction time of hydrates formation was reduced, while THF shows no improvement effect on COB2B hydrate formation. However, the mixture of SDS and THF can promote the hydrate formation rate considerably, and large amount of hydrates formed. In a stirring system with mixture additives, hydrates can form completely about 100 minutes early than that in the quiescent system.

The question of when gas hydrate will become a commercially viable resource most concerns those nations with the most severe energy deficiencies. With the vast potential attributed to gas hydrate as a new gas play, the interest is understandable. Yet the resource potential of gas hydrate has persistently remained just over the horizon. Technical and economic hurdles have pushed back the timeline for development, yet considerable progress has been made in the past five years. An important lesson learned is that an analysis of the factors that control the formation of high grade hydrate deposits must be carried out so that both exploration and recovery scenarios can be modeled and engineered. Commercial hydrate development requires high concentrations of hydrate in porous, permeable reservoirs. It is only from such deposits that gas may be recovered in commercial quantities. While it is unrealistic to consider the global potential of gas hydrate to be in the hundreds of thousands of tcfs, there is a strong potential in the hundreds of tcfs or thousands of tcfs. Press releases from several National gas hydrate research programs have reported gas hydrate “discoveries”. These are, in fact, hydrate shows that provide proof of the presence of hydrate where it may previously only have been predicted. Except in a few isolated areas, valid resource assessments remain to be accomplished through the identification of suitable hosts for hydrate concentrations such as sandstone reservoirs. A focused exploration effort based on geological and depositional characteristics is needed that addresses hydrate as part of a larger petroleum system. Simply drilling in areas that have identifiable bottom simulating reflectors (BSRs) is unlikely to be a viable exploration tool. It is very likely that with drilling on properly identified targets, commercial development could become a reality in less than a decade.

An approach to predictions of position and size of hydrate plugs inside gas wells has been proposed. It is based on the mathematical model of steady non-isothermal flow of real gas in tubes and an algorithm of calculation of equilibrium conditions of hydrate formation. The proposed approach includes the following steps. 1) Numerically solve the system of ordinary differential equations to find the distributions of pressure and temperature along a particular well. 2) Represent the results of calculations as connection between pressure and temperature. 3) Find the intersection of this function with the calculated or experimental equilibrium curve for a particular natural gas. 4) Find the depth of well from the results of numerical solution.

The experimental formation of natural gas hydrate on pendant water droplet exposed to natural gas was conducted and visually observed under the pressures from 3.86MPa to 6.05MPa. The temperature was set at 274.75K and 273.35K. The diameter of the pendant water droplet was around 4mm. The nucleation and growth of hydrate film on the pendant water drop exhibited a generalized trend. The film initially generated at the boundary between the water drop and suspension tube, and afterwards grew laterally and longitudinally on the surface of the water drop. The phenomenon of the two layers of hydrate films growing on the pendant water drop distinguished from the experiments on the sessile water drop. The effect of the driving force that resulted from the overpressure from the three equilibrium pressure on the hydrate nucleation and growth was investigated. It was found that the elevation of the driving force reduced the nucleation time and shortened the process of the hydrate growth on the pendant water drop. The crystals on the hydrate shell became coarser with the increase of the driving force. The mechanism for the hydrate film formation and growth on static pedant water droplet included four stages, such as nucleation, generation of the hydrate film, growth of the hydrate film, and hydration below the hydrate shell.

After reviewing the documents about the studies of hydrate formation kinetics in the world, this paper analyzed the process of hydrate formation on a suspended water droplet, which was based on the hydrate formation with water spay method, proposed a corresponding mathematical model, and solved it. Afterwards, the discussion about this model was presented. The results indicated that equilibrium time diminished with the decrease of the water droplet radius, and prolonged with the increase of sub-cooling degree, the reaction time for the second period reduced with the increase of subcooling degree, but was free from the effect of the variation of the water droplet size. The first period of the hydration on the water droplet was quite short, while the second period was considerably longer. Therefore, shortening the duration time of the second period of hydration was obviously able to accelerate the hydrate formation on the water droplet.

Gas hydrates are found worldwide and many studies have been carried out to develop an efficient method to identify and quantify them using various geophysical as well as other anomalies. In this study, various seismic anomalies related to gas hydrates and the underlying gas are analysed, and correlated them to rock physics properties. Observations of velocities in sediments containing gas hydrates show that the rigidity, and hence the velocity of sediments increases with increase of hydrate saturation. The increase of velocity due to the presence of gas hydrate can be explained in terms of gradual cementation of the sediment matrix. In the case of seismic attenuation, gas hydrate bearing sediments are quite different from common sedimentary rock behaviour of low seismic attenuation with high rigidity. In contrary gas hydrate bearing sediments is observed to have increased seismic attenuation of higher frequencies with increase of hydrate saturation. This strange phenomenon can be explained in terms of differential fluid flow within sediment and hydrate matrix. Also it is observed that the presence of large amount of gas hydrate can result in an increase of seismic amplitudes, a signature similar to the presence of small amount of gas. Hence misinterpretation of these enhanced amplitudes could result in the under estimation of gas present not only as shallow drilling hazard but also on the resource potential of the region. The increase of seismic reflection amplitude results from the formation of gas hydrates in selective intervals causing strong positive and negative impedance contrasts across the formations with and without gas hydrates.

The hydrogen absorption behavior of organic-compound clathrate hydrates was investigated using five kinds of organic compounds as well as tetrahydrofuran (THF). These hydrates were pressurized by hydrogen, and Raman analysis, the determination of the amount of hydrogen and calorimetric measurement were carried out. The Raman results show that the samples investigated in this work formed binary clathrate hydrate of hydrogen and each organic compound. The organic-compound clathrate hydrates presented similar performances to that of THF clathrate hydrate regarding hydrogen absorption and heat of dissociation. These results suggested that the organic compounds investigated in this work may become alternatives to THF.

The inhibitor and steam injection methods have been examined using a laboratory-prepared methane hydrate bearing sediment. New experimental apparatuses have been designed and constructed. In the case of inhibitor injection, the measurement of gas production vs. time suggested that the inhibitor increased dissociation rate. Core temperature decreased upon the inhibitor injection, in contrast to that in the case of pure water injection. The observed pressure differentials between the inlet and outlet of the core sample suggest that the inhibitor effectively prevented the hydrate reformation within the dissociating core sample. In the case of steam injection coupled with depressurization, it can be seen that the effect of steam (or hot water) injection was clear in the later stage of dissociation, compared with that in the case of depressurization alone. The inner (core) temperature change indicates that the coupling of depressurization and steam injection induces MH dissociation from upstream and downstream to the center of the sample. However, it starts from an upstream region and continues downstream steadily in the case of steam (hot water) injection alone.

An underinhibited system is defined as a system where an insufficient amount of thermodynamic inhibitor is present to prevent hydrate formation. Underinhibition might occur due to malfunctioning of equipment, temporary limitations in the inhibitor supplies or operational limitations or errors. Understanding the plugging risk of such systems is important in order to take the correct precautions to avoid blocked flowlines. In this paper we summarize the experimental efforts for the last decade within StatoilHydro on the hydrate plugging risk in underinhibited systems. The flow simulator has been used as the main experimental equipment. The overall results for systems underinhibited with ethylene glycol or methanol show that the plugging potential increases up to a maximum at concentrations around 10-15 wt%. At higher concentrations the plugging potential reduces compared to the uninhibited system. The results can be explained as follows: As water is converted to hydrates in a system containing a thermodynamic inhibitor, the inhibitor concentration will increase until the remaining aqueous phase is inhibited. This self-inhibited aqueous phase will wet the hydrate particles, giving raise to the characteristic term of “sticky” hydrate particles. The aqueous layer surrounding the hydrate particles will form liquid bridges, by capillary attractive forces, upon contact with other hydrate particles or the pipe wall. During the hydrate formation period, there is also a possibility that some of the liquid bridges are converted to solid ones, strengthening the agglomerates. Depending on the oil-water interfacial tension, the phase ratio between the aqueous phase and the solid hydrates and the conversion of liquid bridges to solid ones, this leads to increased plugging risk at lower concentrations of inhibitor (< 20 wt%) and reduced risk at higher concentrations as compared to the uninhibited system.