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.

It has recently been recognized that abundant gas hydrates occur in localized zones of upwelling fluids, with concentrations much higher than in regional distributions associated with bottomsimulating reflectors (BSRs). We report a study of multi-channel seismic reflection data across such structures in the Ulleung Basin, East Sea backarc offshore Korea, an area with few BSRs. The structures are commonly up to several km across and a few hundred meters in depth extent, and are characterized by reduced reflectivity and bowed-up sediment reflectors on time-migrated sections. The seismic pull-up mainly results from higher velocities, although physical deformation due to folding and faulting is not ruled out. Some of the features extend upward close to the seafloor and others only partway through the gas hydrate stability zone. The base of gas hydrate stability zone (BGHSZ), calculated assuming a regional average constant heat flow of 110 mW/m2, is confirmed by the presence of gas inferred from reduced instantaneous frequencies and high instantaneous amplitudes, and from a decrease in seismic velocities. The vents are fed by upward migrating free gas or gas-rich fluids through near-vertical conduits probably due to regional, upward fluid flow caused by tectonic compression of the basin.

Small-scale morphology of gas hydrate is important for understanding the formation of gas hydrate deposits, for estimating the concentrations of gas hydrate from geophysical data, and for predicting their response to climate change or commercial production. The recent use of borehole pressure coring tools has allowed marine gas-hydrate-bearing sediments to be recovered with centimeter to sub-millimeter gas hydrate structures preserved in their in situ condition. Once these sediment samples are recovered at in situ temperature and pressure, nondestructive analyses, including gamma density, P-wave velocity, and X-ray imaging, are used to examine the character of the gas hydrate relative to the structure of the surrounding sediment. Gas hydrate morphology from pressure core data is summarized from the recent national gas hydrate expeditions of India, China, and Korea, as well as from Ocean Drilling Program Leg 204, Integrated Ocean Drilling Program Expedition 311, and the Gulf of Mexico Chevron-Texaco Joint Industry Project. The most striking result is the variability of gas hydrate morphology in clay, ranging from complex vein structures to an invisible pore-filling matrix. Both of these morphologies have been observed in clay sediments at gas hydrate saturations equivalent to 30-40% of pore volume. A clear knowledge of detailed gas hydrate morphology will provide important data to help determine the mechanisms of gas hydrate deposit formation and also provide crucial data for modeling the kinetics of deposit dissociation, from both natural and artificial causes. The morphology also has large effects on sedimentary physical properties, from seismic velocities on a large scale to borehole electrical resistivities on a smaller scale, and gas hydrate morphology will therefore impact estimation of gas hydrate saturation from geophysical data. The detailed morphology of gas hydrate is an essential component for a full understanding of the past, present, and future of any gas hydrate environment.

The paper presents results of the experimental research on the process of CO2 gas hydrates formation in the porous media of sediments under positive and negative temperatures. The subject of research were sediment samples of various compositions including those selected in the permafrost area. The research was conducted in a special pressure chamber, which allowed to monitor pressure and temperature. Using the monitoring results it was possible to make quantitative estimation of the kinetics of CO2 hydrates accumulation in the model sediments. In the course of the research it was demonstrated, that active hydrates accumulation occurred in frozen sediments under negative temperatures (about -4 оС). At the same time a comparative analysis of СО2 and СН4 hydrates accumulation was made in the porous media of the sediment under negative temperatures. The performed experiments enabled to estimate an influence of temperature, sediment composition and water content on kinetics of CO2 hydrates accumulation in porous media. Besides, we made an estimation of the amount of hydrates, which could be formed in hydrates containing sediments at freezing of the remaining pore water.

The mechanisms by which hydrates deposit in a petroleum production-line are likely to be related to pipeline surface properties, e.g. pipeline material, surface energy and roughness. In this work, the wettability alteration of pipeline surfaces from contact with oil, as well as the adhesion energy between water and solid in the presence of oil is investigated. Contact angles are determined as a function of solid material and oil composition, for both model oils and crude oils. Although contact angles in oil/brine/solid systems have been extensively reported in the literature, the variety of solids that may mimic a pipeline is limited. In this study, we include various metal surfaces in addition to glass and a coating. Initial results from using near infrared imaging for collecting contact angle data in non-translucent systems are also presented.

In petroleum production systems, hydrate morphology is observed to be influenced by the crude oil composition. This work is aimed at identifying which crude oil compositional parameters that need to be determined in order to evaluate natural anti-agglomerating properties of crude oils, i.e. the critical compositional descriptors. The compositional features of 22 crude oils have been studied, and multivariate data analysis has been used to investigate the possibility for correlations between several crude oil properties. The results show that biodegradation together with a relatively large amount of acids are characteristic for non-plugging crude oils, while excess of basic compounds is characteristic for plugging crude oils. The multivariate data analysis shows a division of the nonbiodegraded oils, which are all plugging, and the biodegraded oils. In addition, the biodegraded oils seem to be divided into two groups, one with plugging oils and one with mostly non-plugging oils. The results show that the wettability can be predicted from the variables biodegradation level, density, asphaltene content and TAN.

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.

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.