A one-kilometer-diameter carbonate/hydrate mound in Mississippi Canyon Block 118 has been chosen to be the site of a multi-sensor, multi-discipline sea-floor observatory. Several surveys have been carried out in preparation for installing the observatory. The resulting data set permits discussing the mound’s structure in some detail. Samples from the water column and intact hydrate outcrops show gas associated with the mound to be thermogenic. Lithologic and bio-geochemical studies have been done on sediment samples from gravity and box cores. Pore-fluid analyses carried out on these cores reveal that microbial sulfate reduction, anaerobic methane oxidation, and methanogenesis are important processes in the upper sediment. These microbial processes control the diffusive flux of methane into the overlying water column. The activity of microbes is also focused within patches near active vents. This is primarily dependent upon an active flux of hydrocarbon-rich fluids. The geochemical evidence suggests that the fluid flux waxes and wanes over time and that the microbial activity is sensitive to such change. Swath bathymetry by AUV combined with sea-floor video provides sub-meter resolution of features on the surface of the mound. Seismic reflection profiling with source-signature processing resolves layer thicknesses within the upper 200-300m of sediment to about a meter. Exploration-scale 3-D seismic imaging shows that a network of faults connects the mound to a salt diapir a few hundred meters below. Analyses of gases from fluid vents and hydrate outcrops imply that the faults act as migration conduits for hydrocarbons from a deep, hot reservoir. Source-signature-processed seismic traces provide normal-incidence reflection coefficients at 30,000 locations over the mound. Picking reflection horizons at each location allows a 3-D model of the mound’s interior to be constructed. This model provides a basis for understanding the movement of fluids within the mound.

The use of Kinetic Hydrate Inhibitors (KHI) is one of the optimum methods employed to control gas hydrate formation issues and provide flow assurance in oil and gas production systems. The application of this technology has several advantages to operators, including significant cost savings and extended life of oil and gas systems. This paper will highlight a specific case where a Major operator in the North Sea (UK sector) significantly reduced the cost of well intervention operations by applying a KHI in a subsea gas lift line. Considerable cost savings were realized by reducing volume of chemical required and this enabled the application to be performed from the FPSO eliminating the need for a dedicated Diving Support Vessel (DSV). Furthermore, the application of KHI also reduced manual handling and chemical logistics usually associated with this particular treatment. In order to prevent mineral scale deposition occurring in downhole tubing and near well bore and in the formation; scale inhibitor squeeze applications are standard practice. For subsea wells the fluids can be pumped down in to the well via gas lift lines. However, upon completion of previous scale squeeze operations at this particular location, hydrate formation was observed when a mixture of MEG and water was used following interventions via the gas lift line. By applying 1% KHI with a mixture of MEG and Water, the well was brought back into production following scale squeeze operations without hydrate formation occurring.

Formation condition data for methane hydrate in ammonia + water and ammonia + water + tetrahydrofunan (THF) systems are very important for the process development and the determination of operation condition for recycling the vent gas of ammonia synthesis using hydrates. This paper focused on the formation conditions of methane hydrate in the presence of NH3 + H2O and NH3 + H2O + THF system. Equilibrium data of methane hydrate in the temperature, pressure and concentration ranges from 277 to 291 K, 0 to 8 MPa, 1 to 5 % ammonia, were obtained. The experimental results indicate that ammonia has an inhibitive effect on hydrate formation. The higher the concentration of ammonia is, the higher the formation pressure for methane hydrate will be.

In this paper, the effect of additives on COB2B hydrate formation is investigated in a high-pressure test cell surrounded by a thermostated coolant bath. An agitator is configured inside the cell. The characteristics of COB2B gas hydrate formation with additives SDS, THF and mixture of both were discussed. It was found that, in a quiescent system with single SDS，hydrate could form rapidly and the induction time of hydrates formation was reduced, while THF shows no improvement effect on COB2B hydrate formation. However, the mixture of SDS and THF can promote the hydrate formation rate considerably, and large amount of hydrates formed. In a stirring system with mixture additives, hydrates can form completely about 100 minutes early than that in the quiescent system.

The question of when gas hydrate will become a commercially viable resource most concerns those nations with the most severe energy deficiencies. With the vast potential attributed to gas hydrate as a new gas play, the interest is understandable. Yet the resource potential of gas hydrate has persistently remained just over the horizon. Technical and economic hurdles have pushed back the timeline for development, yet considerable progress has been made in the past five years. An important lesson learned is that an analysis of the factors that control the formation of high grade hydrate deposits must be carried out so that both exploration and recovery scenarios can be modeled and engineered. Commercial hydrate development requires high concentrations of hydrate in porous, permeable reservoirs. It is only from such deposits that gas may be recovered in commercial quantities. While it is unrealistic to consider the global potential of gas hydrate to be in the hundreds of thousands of tcfs, there is a strong potential in the hundreds of tcfs or thousands of tcfs. Press releases from several National gas hydrate research programs have reported gas hydrate “discoveries”. These are, in fact, hydrate shows that provide proof of the presence of hydrate where it may previously only have been predicted. Except in a few isolated areas, valid resource assessments remain to be accomplished through the identification of suitable hosts for hydrate concentrations such as sandstone reservoirs. A focused exploration effort based on geological and depositional characteristics is needed that addresses hydrate as part of a larger petroleum system. Simply drilling in areas that have identifiable bottom simulating reflectors (BSRs) is unlikely to be a viable exploration tool. It is very likely that with drilling on properly identified targets, commercial development could become a reality in less than a decade.

13C NMR spectroscopic analysis was carried out to clarify the formed hydrate structure in specific conditions on hydrate phase diagram of ternary methane, neohexane, and water system. The obtained NMR spectra at three different conditions suggested that both structure I and H were formed simultaneously and coexisted at 273.6 K and 50 bar. But, for both conditions of 273.6 K, 25 bar and 283.1 K, 50 bar the formed hydrate was identified as structure H only. These results showed that the pure CH4 hydrate of structure I was formed and coexisted with mixed CH4+neohexane hydrate of structure H in low temperature and high pressure region after passing through the phase boundary of pure CH4 hydrate. We have examined the structure coexistence at 273.6 K and 50 bar with other structure H formers of isopentane, methylcyclopentane, and methylcyclohexane. In case of isopentane, the obtained NMR spectrum showed that structure I and H coexisted and the amount of methane molecules in structure I was two times as many as in cages of structure H. However, there were no resonance lines of structure I when methylcyclohexane formed structure H with methane molecules.

In order to understand the response of authigenic minerals to the gas hydrate geo-system, various authigenic pyrites were picked out under Zeiss Microscope and their S isotopes were analyzed later from 652 sediments samples at intervals of about 1.5m recovered from all 5 sites of Integrated Ocean Drilling Program (IODP) Expedition 311 on Cascadia Margin, northeastern Pacific. SEM photos of picked pyrites exhibit various aggregation features mainly in forms of strawberry, pillar/rod and dumbbell in sizes from 200 m to 1000m. Typical cubic pyrite crystals could be seen under smaller scale SEM photos. Most δ34S values in Site U1325 at the west deeper water location of IODP 311 show negative values low to -33.964‰ CDT, distinctly contrasted to the δ34S in Site U1329 at the east shallower location having much more positive values up to 28.29‰ CDT. At the cold venting position assigned as Site U1328 the δ34S values show strong negative values in the upper part of sediments column above 135 mbsf (meter below sea floor), increasing gradually with the depth from -35.83‰ CDT to -1.32‰ CDT, and then display many positive excursions up to 32.49‰ CDT below 135 mbsf, which is significantly distinguished from the values in nearby non-cold venting Site U1327 having much less positive excursions in the lower part of column below 110 mbsf. In all sites a general negative δ34S excursion occur in the upper part of sediments columns above 30~35 mbsf except in Site U1328 having more depth, indicating the potential current sulfate methane interface (SMI) activity zones. Distinct positive δ34S excursions up to the highest δ34S value 53.65‰ CDT from strawberry pyrites aggregations might indicate that sulfide products by AOM probably inherit completely the sulfate having high δ34S value and no sulfate was left after AOM at a high methane flux under gas hydrate geological background.

An approach to predictions of position and size of hydrate plugs inside gas wells has been proposed. It is based on the mathematical model of steady non-isothermal flow of real gas in tubes and an algorithm of calculation of equilibrium conditions of hydrate formation. The proposed approach includes the following steps. 1) Numerically solve the system of ordinary differential equations to find the distributions of pressure and temperature along a particular well. 2) Represent the results of calculations as connection between pressure and temperature. 3) Find the intersection of this function with the calculated or experimental equilibrium curve for a particular natural gas. 4) Find the depth of well from the results of numerical solution.

The experimental formation of natural gas hydrate on pendant water droplet exposed to natural gas was conducted and visually observed under the pressures from 3.86MPa to 6.05MPa. The temperature was set at 274.75K and 273.35K. The diameter of the pendant water droplet was around 4mm. The nucleation and growth of hydrate film on the pendant water drop exhibited a generalized trend. The film initially generated at the boundary between the water drop and suspension tube, and afterwards grew laterally and longitudinally on the surface of the water drop. The phenomenon of the two layers of hydrate films growing on the pendant water drop distinguished from the experiments on the sessile water drop. The effect of the driving force that resulted from the overpressure from the three equilibrium pressure on the hydrate nucleation and growth was investigated. It was found that the elevation of the driving force reduced the nucleation time and shortened the process of the hydrate growth on the pendant water drop. The crystals on the hydrate shell became coarser with the increase of the driving force. The mechanism for the hydrate film formation and growth on static pedant water droplet included four stages, such as nucleation, generation of the hydrate film, growth of the hydrate film, and hydration below the hydrate shell.

After reviewing the documents about the studies of hydrate formation kinetics in the world, this paper analyzed the process of hydrate formation on a suspended water droplet, which was based on the hydrate formation with water spay method, proposed a corresponding mathematical model, and solved it. Afterwards, the discussion about this model was presented. The results indicated that equilibrium time diminished with the decrease of the water droplet radius, and prolonged with the increase of sub-cooling degree, the reaction time for the second period reduced with the increase of subcooling degree, but was free from the effect of the variation of the water droplet size. The first period of the hydration on the water droplet was quite short, while the second period was considerably longer. Therefore, shortening the duration time of the second period of hydration was obviously able to accelerate the hydrate formation on the water droplet.