Downhole acoustic data were acquired in very low-velocity, hydrate-bearing formations at five sites drilled on the Cascadia Margin during the Integrated Ocean Drilling Program (IODP) Expedition 311. P-wave velocity in marine sediments typically increases with depth as porosity decreases because of compaction. In general, Vp increases from ~1.6 at the seafloor to ~2.0 km/s ~300 m below seafloor at these sites. Gas hydrate-bearing intervals appear as high-velocity anomalies over this trend because solid hydrates stiffen the sediment. Logging-while-drilling (LWD) sonic technology, however, is challenged to recover accurate P-wave velocity in shallow sediments where velocities are low and approach the fluid velocity. Low formation Vp make the analysis of LWD sonic data difficult because of the strong effects of leaky-P wave modes, which typically have high amplitudes and are dispersive. We examine the frequency dispersion of borehole leaky-P modes and establish a minimum depth (approx 50-100 m) below the seafloor at each site where Vp can be accurately estimated using LWD data. Below this depth, Vp estimates from LWD sonic data compare well with wireline sonic logs and VSP interval velocities in nearby holes, but differ in detail due to local heterogeneity. We derive hydrate saturation using published models and the best estimate of Vp at these sites and compare results with independent resistivity-derived saturations.

A short-duration production test was undertaken at the Mallik site in Canada’s Mackenzie Delta in April 2007 as part of the JOGMEC/NRCan/Aurora Mallik 2007 Gas Hydrate Production Research Well Program. Reservoir stimulation was achieved by depressurization of a concentrated gas hydrate interval between 1093 and 1105m (RKB). Geologic and porous media conditions of the production interval have been quantified by geophysical studies undertaken in 2007 and geophysical and core studies undertaken by previous international partnerships in 1998 and 2002. These investigations have documented that the production interval consists of a sand-dominated succession with occasional silty sand interbeds. Gas hydrate occurs mainly within the sediment pore spaces, with concentrations ranging between 50-90%. Laboratory experiments conducted on reconstituted core samples have quantified the effects of pore water salinity and porous media conditions on pressure-temperature stability, suggesting that the partition between gas hydrate stability and instability should be considered as a phase boundary envelope or zone, rather than a discrete threshold. Strength testing on natural core samples has documented the dramatic changes in physical properties following gas hydrate dissociation, with sediments containing no hydrate behaving as unconsolidated sands. While operational problems limited the duration of the production test, a vigorous reservoir response to pressure draw down was observed with increasing gas flow during the testing period. We interpret that pressure temperature (P-T) conditions within the test zone were close to the gas hydrate phase equilibrium threshold, with dissociation initiated at 10 MPa bottomhole pressure (BHP), approximately 1 MPa below in situ conditions. The observation of an increase in production rates at approximately 8.2 MPa BHP may be consistent with the notion of an indistinct gas hydrate stability threshold, with rates increasing as P-T conditions traverse the phase boundary envelope. Significant sand inflow to the well during the test is interpreted to result from the loss of sediment strength during gas hydrate dissociation, with the sediment behaving as a gasified slurry. The increase in gas production rates during the final hours of the test may result from non-uniform gas hydrate dissociation and be affected by accelerated dissociation along water filled natural fractures or fine-scale geologic heterogeneities. These may initiate worm hole or high permeability conduits in association with sand production.

Temporal variations in gas hydrate related geochemical signatures under different deposition conditions are the primary purposes of this study. Accreted wedge located offshore Southwestern Taiwan receives high terrigenous river materials, 100 MT/yr, at present time. It is not clear how seep environment varied during the past glacial. A 25 meters long piston core was taken offshore Southwestern Taiwan on r/v Marion DuFresne. Short piston cores and box cores were also taken on r/v OR-1. Samples were analyzed for pore water dissolved sulfide, sulfate, methane, chloride, del O18, calcium, magnesium, alkalinity, pH, and sediment AVS, pyrite, inorganic carbon, del O- 18, C13. Changes in deposition environment play a major role in the study area. Three stages of geochemical processes are identified in the 25 meters long core, interchange between reduce and oxic depositional environments, with reducing condition in the top 10 m, oxic in between 10-20 meter and reducing below the 20 meter. High concentrations of dissolved sulfide, rapid sulfate depletion, increase of methane, decrease of calcium were found in pore water in the top 10 m of sediments together with high concentrations of pyrite, relatively higher proportion of coarsegrained sediment. Concentrations of pyrite were very low in sediments between 15 to 20 meters but increased rapidly from 20 to 25 meters with a maximum concentration at 400 umol/g. Chloride concentrations also increased to a maximum concentration of 630 mM at 20 m. The rapid increase of chloride indicated gas hydrate formation at this depth. Authigenic carbonate nodules were found in sediments below 20 m. The carbonate content also increased rapidly beneath this depth. Stable isotopic carbon composition of the carbonate varied rapidly beneath 20 m with a low at -28 per mil. The existence of oxic/reducing alterations indicates that methane seep may vary in the past in the study area.

The efficient production of hydrogen hydrates is a major goal in the attempt to exploit those materials as an alternative means for storing hydrogen. Up to now, a few processes have been reported in the literature which yield less than 1 wt% of hydrogen stored into clathrate hydrate or semi-clathrate forms. One main obstacle to the entrapment of sensible amounts of hydrogen (i.e., up to 4 wt% ) into a clathrate matrix appears to be of a kinetic origin, in that the mass transfer of hydrogen gas into clathrate structures is drastically limited by the (relatively) macroscopic scale of the gas-liquid or gas-ice interfaces involved. In this communication, we present a novel process for an enhanced production of binary hydrates of hydrogen and other hydrate-forming gases, which is characterized by the use of nanotechnology for reducing the size of hydrate particles down to a few nanometers. This drastic reduction of particle size, down to three orders of magnitude smaller than that obtainable by macroscopic methods, allows to reduce the kinetic hindrance to hydrate formation. This process has a huge potential for increasing the amount of hydrogen stored, as it has provided ca. 1 wt% of hydrogen, with THF as a co-former. The present process also allows to use several non-water soluble coformers; first reports of hydrogen/cyclopentane and hydrogen/tetrahydrothiophene hydrates are presented.

The equilibrium “pore water in sediment–gas hydrate-former–bulk gas hydrate” was experimentally studied. This residual pore water corresponds to a minimal possible amount of water in the sediment, which is in thermodynamic equilibrium with both gas and the bulk hydrate phase. This pore water can be defined as non-clathrated water by analogy to unfrozen water widely used in geocryological science. The amount of non-clathrated water depends on pressure, temperature, type of sediment, and gas hydrate former. The presence of residual pore water influences the thermodynamic properties of hydrate-saturated samples. The paper’s purpose is to describe a new experimental method for determining the amount of non-clathrated water in sediments at different pressure/temperature conditions. This method is based on measuring the equilibrium water content in an initially air-dried sediment plate that has been placed in close contact with an ice plate under isothermal, hydrate-forming gas pressure conditions. This method was used to measure the non-clathrated water content in kaolinite clay in equilibrium with methane hydrate and CO2 hydrate at a temperature of –7.5o C in a range of gas pressures from 0.1 to 8.7 MPa for methane and from 0.1 to 2.5 MPa for CO2. Experimental data show that at the fixed temperature the non-clathrated water in hydrate-containing sediments sharply reduces when gas pressure increases. The experiment demonstrates that the non-clathrated water content strongly depends on temperature, the mineral structure of sediment, and the hydrate-forming gas.

Hot water injection is a production technique proposed to gas recovery from methane hydrate reservoirs. However, from a practical point of view, the injected water experiences a drop in temperature and re-formation of hydrates may occur in the reservoir. In this work, we proposed a model expressing permeability hysteresis in the processes between hydrate growth and dissociation, and studied hydrate dissociation behavior during hot water injection. The model of permeability hysteresis was incorporated into the simulator MH21-HYDRES (MH21 Hydrate Reservoir Simulator), where the decrease in permeability with hydrate saturation during hydrate growth process was assumed to be much larger than the decrease during hydrate dissociation process. Laboratory hydrate dissociation experiments were carried out for comparison. In each experiment, we injected hot water at a constant rate into a sand-packed core bearing hydrates, and the histories of injection pressure, core temperature, and gas/water production rates were measured. Numerical simulations for the core experiments showed the re-formation of hydrates led to the increase in injection pressure during hot water injection. The simulated tendencies of pressure increase varied markedly by considering permeability hysteresis. Since the experimental pressure increases could not be reproduced without the permeability hysteresis model, the influence of permeability hysteresis should be considered to apply hot water injection to hydrate reservoirs.

Structure I and II gas hydrates were observed in the same sediment cores of a mud volcano in the Kukuy Canyon, Lake Baikal. The sII gas hydrate contained about 13-15% of ethane, whereas the sI gas hydrate contained about 1-5% of ethane and placed beneath the sII gas hydrate. We measured isotopic composition of dissociation gas from both type gas hydrates and dissolved gas in pore water. We found that ethane δD of sI gas hydrate (from -196 to -211 ‰) was larger than that of sII (from -215 to -220 ‰), whereas methane δ13C, methane δD and ethane δD in both hydrate structures were almost the same. δ13C of methane and ethane in gas hydrate seemed several permil smaller than those in pore water. These results support the following idea that the current gas in pore water is not the source of these gas hydrates of both structures. Isotopic data also provide useful information how the “double structure” gas hydrates formed.

To establish the structural and lithological controls on gas hydrate distribution and to assess the potential energy resource and environmental hazards in the Indian Ocean, non-pressurized and pressurized cores were recovered from the Krishna-Godavari (K-G) and Mahanadi Basins offshore east India, and from an Andaman Sea site. The pore fluids were analyzed for: salinity, Cl-, sulfate, sulfide, carbonate alkalinity, Ca2+, Mg2+, Sr2+, K+, Na+, Ba2+, and Li+ concentrations, δ13C-DIC, δ18O, D/H, and 87Sr/86Sr ratios; together with infra-red imaging they provided important constraints on the presence and distribution of gas hydrates, thus on the subsurface hydrology. Evidence for methane hydrate was obtained at each of the sites. Only in the K-G Basin, between the sulfate-methane transition zone (SMT) depth and ~80 mbsf, higher than seawater chloride concentrations are observed; below this zone to the depth of the base of the gas hydrate zone (BGHSZ), chloride concentrations and salinity are lower than seawater value. In the Andaman Sea and Mahanadi Basin, only lower than seawater chloride concentrations are observed, and the shallowest gas hydrates occur at 100-200 m below the sulfate-methane transition zone (SMT) and extend to the depth of the BGHSZ. In the K-G Basin, the highest methane hydrate concentrations are associated with fracture zones in clay-rich sediments and/or in some coarser grained horizons. In the Andaman Sea, however, they are primarily associated with volcanic ash horizons. Assuming dilution by water released from dissociated methane hydrate, chloride and salinity anomalies suggest pore volume occupancies on the order of <1% to a maximum of ~61% at two sites (10, 21) in the K-G Basin and <1% to a maximum of ~76% at the Andaman Sea site. Overall, the percent pore volume occupancies based on pressure core methane concentrations and the chloride concentrations in conventional cores are similar. Variations in sulfate gradients were observed with the steepest gradient having the SMT at 8 mbsf in the K-G Basin and the deepest SMT at ~25 mbsf at the Andaman Sea site. The extreme negative δ13C values of the dissolved inorganic carbon (DIC), ranging from -38‰ to -47‰ at the SMT at some of the sites, indicate that anaerobic oxidation of methane (AOM) is an important reaction responsible for sulfate reduction at these sites. At several sites in the K-G Basin, however, the δ13C-DIC values indicate that organic matter oxidation is the dominant reaction.

The “Integrated Coal Gasification Combined Cycle” (IGCC) represents an advanced approach for green field projects for power generation. This process requires separation of carbon dioxide from the shifted-synthesis gas mixture (fuel gas). Treated fuel gas consists of approximately 40% CO2 and rest H2. Gas hydrate based separation technology for hydrate forming gas mixtures is one of the novel approaches for gas separation. The present study illustrates the gas hydrate-based separation process for the recovery of CO2 and H2 from the fuel gas mixture and discusses relevant issues from macro and molecular level perspectives. Propane (C3H8) is used as an additive to reduce the operating pressure for hydrate formation and hence the compression costs. Based on gas uptake measurement during hydrate formation, a hybrid conceptual process for pre-combustion capture of CO2 is presented. The result shows that it is possible to separate CO2 from hydrogen and obtain a hydrate phase with 98% CO2 in two stages starting from a mixture of 39.2% CO2. Molecular level work has also been performed on CO2/H2 and CO2/H2/C3H8 systems to understand the mechanism by which propane reduces the operating pressure without compromising the separation efficiency.

Studies of geologic and geophysical data from the offshore of India have revealed two geologically distinct areas with inferred gas hydrate occurrences: the passive continental margins of the Indian Peninsula and along the Andaman convergent margin. The Indian National Gas Hydrate Program (NGHP) Expedition 01 was designed to study the occurrence of gas hydrate off the Indian Peninsula and along the Andaman convergent margin with special emphasis on understanding the geologic and geochemical controls on the occurrence of gas hydrate in these two diverse settings. NGHP Expedition 01 established the presence of gas hydrates in Krishna- Godavari, Mahanadi and Andaman basins. The expedition discovered one of the richest gas hydrate accumulations yet documented (Site 10 in the Krishna-Godavari Basin), documented the thickest and deepest gas hydrate stability zone yet known (Site 17 in Andaman Sea), and established the existence of a fully-developed gas hydrate system in the Mahanadi Basin (Site 19).