The hydrogen absorption behavior of organic-compound clathrate hydrates was investigated using five kinds of organic compounds as well as tetrahydrofuran (THF). These hydrates were pressurized by hydrogen, and Raman analysis, the determination of the amount of hydrogen and calorimetric measurement were carried out. The Raman results show that the samples investigated in this work formed binary clathrate hydrate of hydrogen and each organic compound. The organic-compound clathrate hydrates presented similar performances to that of THF clathrate hydrate regarding hydrogen absorption and heat of dissociation. These results suggested that the organic compounds investigated in this work may become alternatives to THF.

The inhibitor and steam injection methods have been examined using a laboratory-prepared methane hydrate bearing sediment. New experimental apparatuses have been designed and constructed. In the case of inhibitor injection, the measurement of gas production vs. time suggested that the inhibitor increased dissociation rate. Core temperature decreased upon the inhibitor injection, in contrast to that in the case of pure water injection. The observed pressure differentials between the inlet and outlet of the core sample suggest that the inhibitor effectively prevented the hydrate reformation within the dissociating core sample. In the case of steam injection coupled with depressurization, it can be seen that the effect of steam (or hot water) injection was clear in the later stage of dissociation, compared with that in the case of depressurization alone. The inner (core) temperature change indicates that the coupling of depressurization and steam injection induces MH dissociation from upstream and downstream to the center of the sample. However, it starts from an upstream region and continues downstream steadily in the case of steam (hot water) injection alone.

In order to obtain a better understanding of hydrate plug formation mechanism in natural gas pipelines, formation and growth of hydrate layer within a rectangular channel formed by brass bottom and top surfaces and an insulated inner and an outer surface of transparent polycarbonate tube was studied experimentally. A gas mixture of 90 % methane balanced with propane was supplied at specified flow rates while the humidity and temperature of the supply gas was controlled at desired values using bubble type saturators and heat exchangers placed in series. Hydrate formation occurred along the top and bottom brass surfaces maintained at temperatures below equilibrium hydrate formation temperature, while the transparent tube served as window for visual observation. A series of carefully controlled laboratory experiments were performed to reveal the shape of porous hydrate layer under different combinations of under-cooling and moisture concentrations. The observed transient characteristics of hydrate layer profiles will provide important data that can be used for validation of numerical models to predict hydrate plugging of natural gas pipelines.

The anti-agglomerating hydrate behavior observed for some crude oils has previously been related to crude oil composition and to surface adsorption mechanisms. Petroleum acids derived from some crude oils have been found able to convert systems with initially high risk of plugging into easily flowable dispersions. In this work, acid fractions are isolated from three oils with low tendency to form hydrate plugs and from two oils associated with high risk of hydrate plugging by using an ion-exchange resin. The extracts are further separated into four sub-fractions by solid phase extraction (SPE). The chemical composition of the fractions is studied by means of HPLC, GPC, FTIR- and UV/VIS spectroscopy and elemental analysis. The distribution of chemical compound classes in the fractions differs between the non-plugging and plugging oils, and the differences are most distinctive in one of the sub-fractions. The results imply that acid sub-fractions holding a significant proportion of more weakly polar compounds, like ester functionalities, are important for how the hydrate surfaces and the oil phase interact.

An underinhibited system is defined as a system where an insufficient amount of thermodynamic inhibitor is present to prevent hydrate formation. Underinhibition might occur due to malfunctioning of equipment, temporary limitations in the inhibitor supplies or operational limitations or errors. Understanding the plugging risk of such systems is important in order to take the correct precautions to avoid blocked flowlines. In this paper we summarize the experimental efforts for the last decade within StatoilHydro on the hydrate plugging risk in underinhibited systems. The flow simulator has been used as the main experimental equipment. The overall results for systems underinhibited with ethylene glycol or methanol show that the plugging potential increases up to a maximum at concentrations around 10-15 wt%. At higher concentrations the plugging potential reduces compared to the uninhibited system. The results can be explained as follows: As water is converted to hydrates in a system containing a thermodynamic inhibitor, the inhibitor concentration will increase until the remaining aqueous phase is inhibited. This self-inhibited aqueous phase will wet the hydrate particles, giving raise to the characteristic term of “sticky” hydrate particles. The aqueous layer surrounding the hydrate particles will form liquid bridges, by capillary attractive forces, upon contact with other hydrate particles or the pipe wall. During the hydrate formation period, there is also a possibility that some of the liquid bridges are converted to solid ones, strengthening the agglomerates. Depending on the oil-water interfacial tension, the phase ratio between the aqueous phase and the solid hydrates and the conversion of liquid bridges to solid ones, this leads to increased plugging risk at lower concentrations of inhibitor (< 20 wt%) and reduced risk at higher concentrations as compared to the uninhibited system.

Nonadhesive hydrate slurries have been shown to exhibit low viscosities in a field-scale flow loop when formed under appropriate conditions. The factors that favor formation of low-viscosity hydrate slurries include high Reynolds Number and Capillary Number, and high mass transfer and heat transfer rates. High liquid loading and high superficial fluid velocities are found to be conducive to the formation of low viscosity hydrate slurries. Dispersed bubble flow has been observed to facilitate flowable hydrate slurry production. Alternatively, the formation of nonadhesive hydrates at moderate superficial velocity is possible when a static mixer is used upstream of the hydrate formation location. For certain fields, low-viscosity hydrate slurry technology could eliminate the need for insulation and hydrate inhibitor chemicals (revised version of ICGH 2008 paper 5818) .

As part of an international cooperative research program, the U.S. Geological Survey (USGS) and researchers from the National Gas Hydrate Program (NGHP) of India are studying the physical properties of sediment recovered during the NGHP-01 cruise conducted offshore India during 2006. Here we report on index property, acoustic velocity, and triaxial shear test results for samples recovered from the Krishna-Godavari Basin. In addition, we discuss the effects of sample storage temperature, handling, and change in structure of fine-grained sediment. Although complex, sub-vertical planar gas-hydrate structures were observed in the silty clay to clayey silt samples prior to entering the Gas Hydrate And Sediment Test Laboratory Instrument (GHASTLI), the samples yielded little gas post test. This suggests most, if not all, gas hydrate dissociated during sample transfer. Mechanical properties of hydrate-bearing marine sediment are best measured by avoiding sample depressurization. By contrast, mechanical properties of hydrate-free sediments, that are shipped and stored at atmospheric pressure can be approximated by consolidating core material to the original in situ effective stress.

The Scotian margin of the east coast of Canada has a large theoretical gas hydrate stability zone (GHSZ) yet review of extensive industry seismic data reveals a prominent BSR at only one location. 3D seismic reflection and long offset (9 km) pre-stack 2D multichannel seismic data were used to study the velocity structure and geophysical characteristics of the hydrate zone and surrounding regions. The Mohican Channel study area shows a unique double BSR at 300 to 450 m below the seafloor in the western section of the study area immediately adjacent to the Mohican Channel in a water depth range of 1500- 1930m. The topmost BSR (BSR 1) is the more extensive of the two covering an area of 150 km2 in the 3D volume and a calculated area of 280 km2 using 2D industry and single-channel seismic profiles outside of the study area. BSR 2 covers an area of ~50 km2 and occurs approximately 80m below BSR 1. A system of polygonal faults is prominent in the area and some faults appear as conduits for gas leakage into the GHSZ. Fluid escape features are common on the surface of BSR 1 but rare on the seafloor suggesting that fluid flux is at lower levels than in the past.

It was proposed that erosion of subsea ridges on the Hikurangi margin may be linked to a fluctuating level of the top of gas hydrate stability in the ocean. Since publication of this hypothesis, three field campaigns were conducted in the study area. Here we summarize relevant results from these cruises. We found that water temperature fluctuations occur at lower frequencies and higher amplitudes than previously thought, making it more likely that temperature changes reach sub-seafloor gas hydrates. Dredge samples encountered numerous consolidated mudstones. We speculate that gas hydrate “freeze-thaw” cycles may lead to dilation of fractures in mudstones due to capillary forces, weakening the seafloor. Ubiquitous gas pockets beneath the ridge may lead to overpressure that may also contribute to seafloor fracturing.

Monitoring of the seafloor for gas hydrate dissociation around boreholes during hydrocarbon production is likely to involve seismic methods because of the strong sensitivity of P-wave velocity to gas in sediment pores. Here, based on geomechanical models, we apply commonly used rock physics modeling to predict the seismic response to gas hydrate dissociation with a focus on P-impedance and performed sensitivity tests. For a given initial gas hydrate saturation, the mode of gas hydrate distribution (cementation, frame-bearing, or pore-filling) has the strongest effect on P-impedance, followed by the mesoscopic distribution of gas bubbles (evenly distributed in pores or “patchy”), gas saturation, and pore pressure. Of these, the distribution of gas is likely to be most challenging to predict. Conceptual 2-D FD wave-propagation modeling shows that it could be possible to detect gas hydrate dissociation after a few days.