We study hydrate formation and distribution in two scales. Pore-scale network modeling for drainage and imbibition and 1D field-scale sedimentological model are proposed for such purpose. The network modeling is applied in a novel way to obtain the possible hydrate and fluid saturations in the porous medium. The sedimentological model later uses these results to predict field-scale hydrate distribution. In the model proposed by (Behseresht et al., 2009a), gas charge in the reservoir firstly takes place when BGHSZ (Base of Gas Hydrate Stability Zone) is still above the reservoir. Methane gas migrates from deep source and is contained in the reservoir by the capillary barrier. The gas saturation distribution is determined by gas/water capillary pressure, and is modeled by network modeling of drainage. When gas charge is complete, the gas column in the reservoir is assumed to be disconnected from the deep source, and BGHSZ begins to descend. Hydrate formation is assumed to occur only at BGHSZ. At the microscopic scale it first occurs at the methane/water interface. A review of the possible modes of growth leads to the assumption that hydrate grows into the gaseous phase. It is assumed that the hydrate formation at the pore scale follows the path of imbibition process (displacement of gas phase by aqueous phase), and can be predicted by the network modeling of imbibition. Two scenarios, corresponding to slow and fast influx of water to the BGHSZ, are proposed to give the maximum and minimum hydrate saturations, respectively. The volume of hydrate is smaller than the total volume of gas and water that are converted at fixed temperature and pressure. Therefore, vacancy is created to draw free gas from below the BGHSZ and water into the BGHSZ. BGHSZ keeps descending and converting all the gas at BGHSZ into hydrate. The final hydrate profile has a characteristic pattern, in which a region of high hydrate saturation sits on top of a region with low hydrate saturation. This pattern agrees with the observation in Mount Elbert and Mallik sites. The low hydrate saturation in certain regions with good lithology shows that hydrate distribution is not only controlled by the quality of lithology, but also the gas redistribution during hydrate formation. / text

Many Arctic gas hydrate reservoirs such as those of the Prudhoe Bay and Kuparuk River area on the Alaska North Slope (ANS) are believed originally to be natural gas accumulations converted to hydrate after being placed in the gas hydrate stability zone (GHSZ) in response to ancient climate cooling. A mechanistic model is proposed to predict/explain hydrate saturation distribution in “converted free gas” hydrate reservoirs in sub-permafrost formations in the Arctic. This 1-D model assumes that a gas column accumulates and subsequently is converted to hydrate. The processes considered are the volume change during hydrate formation and consequent fluid phase transport within the column, the descent of the base of gas hydrate stability zone through the column, and sedimentological variations with depth. Crucially, the latter enable disconnection of the gas column during hydrate formation, which leads to substantial variation in hydrate saturation distribution. One form of variation observed in Arctic hydrate reservoirs is that zones of very low hydrate saturations are interspersed abruptly between zones of large hydrate saturations. The model was applied on data from Mount Elbert well, a gas hydrate stratigraphic test well drilled in the Milne Point area of the ANS. The model is consistent with observations from the well log and interpretations of seismic anomalies in the area. The model also predicts that a considerable amount of fluid (of order one pore volume of gaseous and/or aqueous phases) must migrate within or into the gas column during hydrate formation. This work offers the first explanatory model of its kind that addresses "converted free gas reservoirs" from a new angle: the effect of volume change during hydrate formation combined with capillary entry pressure variation versus depth. Mechanisms by which the fluid movement, associated with the hydrate formation, could have occurred are also analyzed. As the base of the GHSZ descends through the sediment, hydrate forms within the GHSZ. The net volume reduction associated with hydrate formation creates a “sink” which drives flow of gaseous and aqueous phases to the hydrate formation zone. Flow driven by saturation gradients plays a key role in creating reservoirs of large hydrate saturations, as observed in Mount Elbert. Viscous-dominated pressure-driven flow of gaseous and aqueous phases cannot explain large hydrate saturations originated from large-saturation gas accumulations. The mode of hydrate formation for a wide range of rate of hydrate formation, rate of descent of the BGHSZ and host sediments characteristics are analyzed and characterized based on dimensionless groups. The proposed transport model is also consistent with field data from hydrate-bearing sand units in Mount Elbert well. Results show that not only the petrophysical properties of the host sediment but also the rate of hydrate formation and the rate of temperature cooling at the surface contribute greatly to the final hydrate saturation profiles. / text

In 1995, the U.S. Geological Survey made the first systematic assessment of the in-place natural gas hydrate resources of the United States. That study suggested that the amount of gas in the gas hydrate accumulations of northern Alaska probably exceeds the volume of known conventional gas resources on the North Slope. Researchers have long speculated that gas hydrates could eventually be a commercial resource yet technical and economic hurdles have historically made gas hydrate development a distant goal rather than a near-term possibility. This view began to change over the past five years with the realization that this unconventional resource could be developed in conjunction with conventional gas fields. The most significant development was gas hydrate production testing conducted at the Mallik site in Canada’s Mackenzie Delta in 2002. The Mallik 2002 Gas Hydrate Production Research Well Program yielded the first modern, fully integrated field study and production test of a natural gas hydrate accumulation. More recently, BP Exploration (Alaska) Inc. with the U.S. Department of Energy and the U.S. Geological Survey have successfully cored, logged, and tested a gas hydrate accumulation on the North Slope of Alaska know as the Mount Elbert Prospect. The Mallik 2002 project along with the Mount Elbert effort has for the first time allowed the rational assessment of the production response of a gas hydrate accumulation.