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

Two internationally-partnered research well programs, in 1998 and 2002, studied the Mallik gas hydrate accumulation in the Mackenzie Delta, Canada. Gas hydrate bearing intervals were cored, logged and production tested thus establishing Mallik as an excellent site for testing geophysical imaging techniques. Here, we apply a model-based acoustic impedance inversion technique to 3D seismic reflection data acquired over the Mallik area to characterize gas hydrate occurrences and to help define their spatial extent away from well control. Sonic logs in Mallik research wells show that P-wave velocity of sediments increases with hydrate saturation, enough to produce detectable reflections for the lower two of three known gas hydrate zones. The inversion method converts these reflections into acoustic impedances from which velocity and hydrate saturation can be estimated. Acoustic impedance inversion results indicate that the deepest gas hydrate zone covers an area of approximately 900,000 m2. With some assumptions on the lateral continuity of gas hydrate saturation, porosity and thickness measured at the wells, we estimate that this zone contains approximately 771x106 m3 of gas at standard atmospheric pressure. At a regional scale, results allowed the detection of a high-velocity area near the A-06 well, about 6 km south-east of 5L-38. We infer that the high velocity area corresponds to a gas hydrate accumulation. Logging data in A-06 indicate the presence of gas hydrates in this area and support our interpretation.

The presence of gas hydrates in permafrost regions has been confirmed by core samples recovered from the Mallik gas hydrate research wells located within Mackenzie Delta in the Northwest Territories of Canada. Strong vertical variations of compressional and shear velocities and weak surface seismic expressions of gas hydrates indicate that lithological heterogeneities control the lateral distribution of gas hydrates. Seismic scattering studies predict that typical horizontal scales and strong velocity contrasts due to gas hydrate concentration will generate strong forward scattering, leaving only weak energy to be captured by surface receivers. In order to understand the distribution of gas hydrates and the scattering effects on seismic waves, heterogeneous petrophysical reservoir models were constructed based on the P-wave and S-wave velocity logs. Random models with pre-determined heterogeneity scales can also be used to simulate permafrost interval as well as sediments without hydrates. Using the established relationship between hydrate concentration and P-wave velocity, we found that gas hydrate volume content can be determined by correlation length and Hurst number. Using the Hurst number obtained from Mallik 2L-38, and the correlation length estimated from acoustic impedance inversion, gas hydrate volume fraction in Mallik area was estimated to be 17%, approximately 7x108 m3 free gas stored in a hydrate bearing interval with 250,000 m2 lateral extension and 100 m depth. Simulations of seismic wave propagation in randomly heterogeneous models demonstrate energy loss due to scattering. With the available modeling algorithm, the impact of heterogeneity scales on seismic scattering and optimum acquisition geometries will be investigated in future studies.

Geochemical processes associated with gas hydrate formation lead to the growth of iron sulphides which have a geophysically-measurable magnetic signature. Detailed magnetic investigation, complemented by petrological observations, were undertaken on cores from a permafrost setting, the Mackenzie Delta (Canadian Northwest Territories) Mallik region, and two marine settings, IODP Expedition 311 cores from the Cascadia margin off Vancouver Island and the Indian National Gas Hydrate Program Expedition 1 from the Bengal Fan. Stratigraphic profiles of the fine scale variations in bulk magnetic measurements correspond to changes in lithology, grain size and pore fluid geochemistry which can be correlated on local to regional scales. The lowest values of magnetic susceptibility are observed where iron has been reduced to paramagnetic pyrite, formed in settings with high methane and sulphate or sulphide flux, such as at methane vents. High magnetic susceptibility values are observed in sediments which contain detrital magnetite, for example from glacial deposits, which has survived diagenesis. Other high magnetic susceptibility values are observed in sediments in which the ferrimagnetic iron-sulphide minerals greigite or smythite have been diagenetically introduced. These minerals are mostly found outside the sediments which host gas hydrate. The mineral textures and compositions indicate rapid disequilibrium crystallization. The unique physical and geochemical properties of the environments where gas hydrates form, including the availability of methane to fuel microbiological activity and the concentration of pore water solutes during gas hydrate formation, lead to iron sulphide precipitation from solute-rich brines. Magnetic surveying techniques help delineate anomalies related to gas hydrate deposits and the diagenesis of magnetic iron minerals related to their formation. Detailed core logging measurements and laboratory analyses of magnetic properties provide direct ties to original lithology, petrophysical properties and diagenesis caused by gas hydrate formation.

Using cryogenic SEM, we investigated the physical states of gas-hydrate-bearing samples recovered by drill core from several localities including the SE India margin (NGHP Expedition 01), Cascadia margin (IODP Leg 311), Gulf of Mexico (RV Marion Dufresne 2002), and Mackenzie River Delta (Mallik site, well 5L-38). Core material with a significant fraction of preserved hydrate has only been obtained for cryogenic SEM investigation from relatively few sites worldwide to date, yet certain consistent textural characteristics, as well as some clear differences between sites have been observed. Gas hydrate in cores recovered from Cascadia, Gulf of Mexico, and Mallik often occurs as a dense substrate with typical grain size of 30 to as large as 200 μm. The hydrate often contains a significant fraction of isolated macropores that are typically 5–100 μm in diameter and occupy 10-30 vol. % of the domain. In fine-grained sediment sections of marine samples, gas hydrate commonly forms small pods or lenses with clay platelets oriented sub-parallel around them, or as thin veins 50 to several hundred microns in thickness. In some sections, hydrate grains are delineated by a NaCl-bearing selvage that forms thin rinds along hydrate grain exteriors, presumably produced by salt exclusion during original hydrate formation. Preliminary assessment of India NGHP-01 samples shows some regions consistent with the observations described above, as well as other regions dominated by highly faceted crystals that line the walls or interior of cavities where the hydrate grows unimpeded. Here, we focus on gas hydrate grain morphology and microstructures, pore characteristics and distribution, and the nature of the hydrate/sediment grain contacts of the recovered samples, comparing them to each other and to laboratory-produced gas hydrates grown under known conditions.