Gas hydrate has been identified by drilling in Alaminos Canyon block 818, within the Perdido Fold Belt, outboard of the Sigsbee Escarpment, in approximately 2750 meters (9000 feet) of water. At the location of the AC818 #1 (“Tigershark”) well, the gas hydrate occurs within the top 20 m (65 feet) of an approximately 90 meter (300 feet) thick Oligocene Frio sand, a volcaniclastic sandstone rich in lithic fragments, feldspar, and volcanic ash. The Frio reservoir is folded into a 4-way closed anticline. At the crest of the anticline, the sand is partly eroded and is unconformably overlain by 450 m (1500 feet) of Pleistocene shale and sand. The unconformity surface is also in a 4-way closed geometry and defines the top of the hydrate reservoir at the well. The rock is poorly consolidated and has porosity as high as 42% from log data. LWD logs indicate that the hydrate zone has high resistivity and high P-velocity (2750 mps: 9000 fps). The underlying wet sand at the base of the gas hydrate stability zone (GHSZ) has low resistivity and P-velocity (Vp: 1500 mps: 5000 fps). The very low Vp indicates the presence of low-saturation free gas ("fizz gas"). The large velocity contrast creates a strong response in seismic data which was inverted into a 3D gas hydrates saturation (Sgh) volume. Elsewhere in the GHSZ, seismic character was used to predict predominant sediment facies. Relative high stand facies, which are more clay-rich, will generally be characterized by more continuous and parallel seismic reflectors. In contrast, relative low stand facies, which have more sand content, will be characterized by more hummocky, discontinuous seismic character and will often lie on erosional surfaces, particularly in uncompacted sediments. Understanding the stratigraphy throughout the section is important, since sand will often provide beneficial reservoir conditions, while clay will provide more impervious sealing qualities. The seismic interpretation also identifies migration pathways, such as faults and gas chimneys, and the presence of available gas, which are necessary to charge reservoirs within the HSZ.

Hydrates in some crude oils have a smaller tendency to form plugs than in others, and lately this is becoming a focus of research. To study this and the action of hydrate antiagglomerants in general, hydrate surface properties must be known. To help in characterizing the surface properties by simulation, the capillary waves of clathrate hydrate surfaces in vacuum are examined in all unique crystal faces by Molecular Dynamics, and an attempt is made to estimate the surface energies in the respective crystal faces from the wave fluctuations [1]. We also attempt to estimate solid/liquid surface energies of hydrate/oil and hydrate/water for a specific face, for comparison. The forcefield OPLS_AA is used for the organic compounds, while TIP4P/ice is used for the water framework. The anisotropy of the surface energy is then estimated and the result compared to the initial growth rate of different crystal faces as found in experiment [2].

Gas hydrates in near-mudline subsea sediments present significant challenges in the production of underlying hydrocarbons, impacting wellbore integrity and placement of subsea equipment. As the fluids of an underlying reservoir flow to the mudline, heat carried by the fluids warms nearwell sediments and dissociates hydrates, which releases gas that can displace and fracture near well soil. This gas release may be calculated with numerical simulations that model heat and mass transfer in hydrate-bearing sediments. The nature and distribution of hydrates within the sediments, the melting behavior of the hydrates, the thermal and mechanical properties of these shallow sediments, and the amount of hydrates contained in the sediments are required for the model simulations. Such information can be costly to acquire and characterize with certainty for an offshore development. In this information environment, it is critical to understand what information, processes, and calculations are required in order to ensure safe, robust systems, that are not overly conservative, to produce the hydrocarbon reservoirs far below the hydrates.

The purpose of the work is to show how to employ the experimental data from geocryology and soil physics for thermodynamic calculations of gas hydrate phase equilibria by taking into account pore water behavior in sediments. In fact, thermodynamic calculation is used here to determine the amount of non-clathrated pore water content in sediments in equilibrium with gas and hydrate phases. A thermodynamic model for pore water behavior in sediments is developed. Taking into account the experimental water potential data, the model calculations show good agreement with the experimentally measured unfrozen water content for different pressure and temperature conditions. The proposed thermodynamic model is applied for calculations of three-phase equilibria: multicomponent gas phase (methane, natural gas, etc.) – pore water in clay, sand, loamy sand, etc. – bulk (or pore) hydrate. As a result, correlations have been established between unfrozen and non-clathrated water content in natural sediments.

A thermodynamic inhibitor - methanol is used for hydrates control both at gas-gathering pipelines and gas conditioning / treatment field plants of Novatek JSC. Due to severe climate conditions and absence of serious infrastructure high operation costs for hydrate control take place. For reducing inhibitor losses some new technological solutions were proposed including recycling and regeneration of saturated methanol. A small module for producing methanol at field conditions was designed. Technological schemes for methanol injection and recirculation are discussed. These technologies reduce methanol losses. Small methanol-producing plant at Yurkharovskoe gas-condensate field (12.5 million ton methanol per year) integrated with field gas treatment plant is presented. The technology includes producing converted gas (syngas) from natural gas, catalytic process for raw methanol synthesis and rectification of raw methanol at final stage. Some particularities of the integrated technology are as follows. Not needs for preliminary purification of required raw materials (natural gas and water). Dried natural gas after conditioning (without any traces of sulfuric compounds) and pure water from simplified water treatment block are used. Rectification of raw methanol is combined with rectification of saturated methanol from gas treatment plant. Economic estimations show that the integrated methanol-producing technology and optimization of methanol circulation in technological processes essentially reduce capital and operational costs for hydrate control at northern gas and gas-condensate fields.

Active marine electromagnetic methods have proven to be a powerful tool to detect resistivity anomalies associated with gas hydrate. However, because the propagation of electromagnetic fields for these methods works in the diffusive regime the spatial resolution of the resistivity structure is limited. So far only bulk electrical properties have been estimated from measured data, although hydrate bearing layers are found to be highly heterogeneous. We computed response curves for synthetic one- and two-dimensional models to investigate the resolution capabilities for various measurement geometries with respect to resistive features. Electric dipole transmitters (TXs) are used as sources. In the marine case, the in-line electric dipole-dipole configuration has proven its capabilities to detect the shallow resistive gas-hydrate. Our model study demonstrates that both the depth to a resistive feature can be resolved nicely using data for multiple TX-RX offsets. However, resolving smaller features of the resistive zone, for example if the zone is split in separate resistive layers, is extremely difficult. The resolution of the target can be improved using electrical downhole transmitters. So far there have been no reports of the detection of permafrost gas hydrate deposits with surface electromagnetic methods. Our calculations show that a similar setup to that used in the marine case is capable of detecting gas hydrate on land. The resolution, however, is lower than for the marine case, because of the significantly greater depths to the target.

Enormous amount of latent heat generates/absorbs at the formation/dissociation process of gas hydrates and controlls their thermal condition themselves. In this paper we investigated the effect of ethane concentration on dissociation heat of mixed-gas (methane and ethane) hydrate. It has been reported by researchers that a structure II gas hydrate appears in appropriate gas composition of methane and ethane. We confirmed by using Raman spectroscopy that our samples had the following three patterns: structure I only, structure II only and mixture of structures I and II. Dissociation heats of the mixed-gas hydrates were within the range between those of pure methane and ethane hydrates and increased with ethane concentration. In most cases two peaks of heat flow appeared and the dissociation process was divided into two parts. This can be understood in the following explanation that (1) the sample contained both crystal structures, and/or (2) ethane-rich gas hydrate formed simultaneously from dissociated gas and showed the second peak of heat flow.

Dissociation and specific heats of synthetic methane and ethane hydrates were measured under high-pressure condition by using a heat-flow type calorimeter to understand thermodynamic properties of gas hydrates under submarine/sublacustrine environments. Ice powder was put into the sample cell and pressurized by methane and ethane up to 5MPa and 2MPa, respectively. After the completion of gas hydrate formation, samples were heated from 263K to 288K at the rate of 0.01 K min-1. Large negative peaks of heat flow corresponded to the dissociation of gas hydrates were detected in a temperature range 279-282K at a pressure of 5MPa for methane hydrate and 283-286K at 2MPa for ethane hydrate, respectively. We also obtained the specific heats of gas hydrates in the range 264-276K for methane and 264-282K for ethane under pressure.

Natural gas hydrates occur on most continental margins in organic-rich sediments at water depths >450 m (in polar regions >150 m). Gas hydrate distribution and abundance, however, varies significantly from margin to margin and with tectonic environment. The National Gas Hydrate Program (NGHP) Expedition 01 cored 10 sites in the Krishna-Godawari (K-G) basin, located on the southeastern passive margin of India. The drilling at the K-G basin was comprehensive, providing an ideal location to address questions regarding processes that lead to variations in gas hydrate concentration and distribution in marine sediments. Pore fluids recovered from both pressurized and non-pressurized cores were analyzed for salinity, Cl-, SO4 2-, alkalinity, Ca2+, Mg2+, Sr2+, Ba2+, Na+, and Li+ concentrations, as well as 􀀂13C-DIC, 􀀂18O, and 87/86Sr isotope ratios. This comprehensive suite of pore fluid concentration and isotopic profiles places important constraints on the fluid/gas sources, transport pathways, and CH4 fluxes, and their impact on gas hydrate concentration and distribution. Based on the Cl- and 􀀂18􀀁 depth profiles, catwalk infrared images, pressure core CH4 concentrations, and direct gas hydrate sampling, we show that the occurrence and concentration of gas hydrate varies considerably between sites. Gas hydrate was detected at all 10 sites, and occurs between 50 mbsf and the base of the gas hydrate stability zone (BGHSZ). In all but three sites cored, gas hydrate is mainly disseminated within the pore space with typical pore space occupancies being 􀀁2%. Massive occurrences of gas hydrate are controlled by high-angle fractures in clay/silt sediments at three sites, and locally by lithology (sand/silt) at the more “diffuse” sites with a maximum pore space occupancy of ~67%. Though a majority of the sites cored contained sand/silt horizons, little gas hydrate was observed in most of these intervals. At two sites in the K-G basin, we observe higher than seawater Cl- concentrations between the sulfate-methane transition (SMT) and ~80 mbsf, suggesting active gas hydrate formation at rates faster than Cl- diffusion and pore fluid advection. The fluids sampled within this depth range are chemically distinct from the fluids sampled below, and likely have been advected from a different source depth. These geochemical results provide the framework for a regional gas hydrate reservoir model that links the geology, geochemistry, and subsurface hydrology of the basin, with implications for the lateral heterogeneity of gas hydrate occurrence in continental margins.

Natural gas hydrates store a substantial portion of the Earth's organic carbon, although their occurrence is restricted by thermobaric boundaries and the availability of methane-rich fluids. The complexity of geological systems and the multiphase flow processes promoting hydrate formation can result in a mismatch between the predicted and the observed hydrate distribution. The purpose of this research is to achieve a better comprehension of the factors that influence the distribution of gas hydrates and the mechanism of fluid movements beneath and across the gas hydrate stability zone (GHSZ). Therefore, this study integrates seismic, petrophysical and geochemical data from different gas hydrate provinces. This work provides evidence that hydrates can occur below bottom-simulating reflectors, in the presence of sourcing thermogenic hydrocarbons. The relationship between fluid-escape pipes and gas hydrates is further explored, and pipe-like features are suggested to host a significant volume of hydrates. The host lithology also represents a critical factor influencing hydrate and free gas distribution and, in evaluating a natural gas hydrate system, needs to be considered in conjunction with the spatial variability in the methane supply. The three-dimensional distribution of gas hydrate deposits in coarse-grained sediments, representing the current target for hydrate exploration, is shown to be correlated with that of the underlying free gas zone, reflecting sourcing mechanisms dominated by a long-range advection. In such systems, the free gas invasion into the GHSZ appears controlled by the competition between overpressure and sealing capacity of the gas hydrate-bearing sediments. Globally, the thickness of the free gas zones is regulated by the methane supply and by different multi-phase flow processes, including fracturing, capillary invasion and possibly diffusion. In conclusion, this research indicates that geological, fluid flow and stability factors interweave at multiple scales in natural gas hydrate systems.