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Reducing atmospheric CO2, a main source of greenhouse gas, has been accentuated recently. One focus is capture, separation, and sequestration of industrial CO2. As a hydrate former, CO2 forms hydrates at moderate temperatures and pressures. This phenomenon could be utilized to capture and separate CO2 from flue gases, and also has the potential to sequester CO2 in the deep sds. This research investigated the CO2-N2 separation efficiency of gas hydrates; it investigated the sequestration potential of CO2 hydrates in ocean sediments. The catalytic effect of surfactants in these processes was investigated. A fluorosurfactant FS-62 was mixed with SDS at 100ppm/1000ppm was found to best catalyze CO2 hydrate formation, giving a high formation rate of 0.1239 mmole of occluded gas/minute-about 2.87 times the base case with no surfactant. FS-62/SDS was verified to increase the separation efficiency of N2-CO2 gas which formed a mixture gas hydrate. In a two-stage process, a desirable separation efficiency was obtained. A total CO2 removed from the gas mixture of 67.7% was obtained. In a series of experiments simulated under ocean sediment environments, the biosurfactants Emulsan and Rhamnolipid showed favorable catalysis of CO2 hydrate formation. Also, the chemical structure of the porous media was found to have some influence on the hydrate formation rate. For a quiescent system, the displacement of natural gas from hydrate by injecting CO2 occurred at a low level and would not be a practical process. In the case of displacing CH4 from hydrate with CO2, no displacement would occur. This research work showed that a potentially cost effective hydrate separation technology applied to N2-CO2 gas, representative of a flue gas, can be improved by adding surfactants. It was found that biosurfactants give some beneficial effect on CO2 hydrate formation in sediments and might be used to assist CO2 sequestration in sediments or to displace natural gas from hydrates already in sediments.

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No / A crystalline solid called a gas hydrate has gas molecules surrounded by water molecules. There are several gases with suitable structures for the production of hydrates, but methane-rich gas hydrates are more common and form in seas and on the ocean. The place of hydrates formation is usually the sediment of the ocean floor and the polar regions, which largely covered with ice. It is also found in large quantities in combination with ambient ice in the ever-frozen polar regions. The importance of gas hydrates is due to the great ability of gas hydrates in natural gas storage, which makes it attractive to use them for the purposes of storing and transporting natural gas and other gases as a competitor to liquefaction and condensing methods. Due to the significance potential of these reserves as the world's future energy supplier and their direct impact on changes in climate conditions due to the greenhouse effect of methane, as well as their geological risks during water hydrocarbon discoveries, marine science researchers have been studying them over the past few years. Acoustic and seismic methods are helpful instruments for measuring subterranean hydrated reserves because there is not the technology to measure hydrated reserves directly.

Many Arctic gas hydrate reservoirs such as those of the Prudhoe Bay and Kuparuk River area on the Alaska North Slope (ANS) are believed originally to be natural gas accumulations converted to hydrate after being placed in the gas hydrate stability zone (GHSZ) in response to ancient climate cooling. A mechanistic model is proposed to predict/explain hydrate saturation distribution in “converted free gas” hydrate reservoirs in sub-permafrost formations in the Arctic. This 1-D model assumes that a gas column accumulates and subsequently is converted to hydrate. The processes considered are the volume change during hydrate formation and consequent fluid phase transport within the column, the descent of the base of gas hydrate stability zone through the column, and sedimentological variations with depth. Crucially, the latter enable disconnection of the gas column during hydrate formation, which leads to substantial variation in hydrate saturation distribution. One form of variation observed in Arctic hydrate reservoirs is that zones of very low hydrate saturations are interspersed abruptly between zones of large hydrate saturations. The model was applied on data from Mount Elbert well, a gas hydrate stratigraphic test well drilled in the Milne Point area of the ANS. The model is consistent with observations from the well log and interpretations of seismic anomalies in the area. The model also predicts that a considerable amount of fluid (of order one pore volume of gaseous and/or aqueous phases) must migrate within or into the gas column during hydrate formation. This work offers the first explanatory model of its kind that addresses "converted free gas reservoirs" from a new angle: the effect of volume change during hydrate formation combined with capillary entry pressure variation versus depth. Mechanisms by which the fluid movement, associated with the hydrate formation, could have occurred are also analyzed. As the base of the GHSZ descends through the sediment, hydrate forms within the GHSZ. The net volume reduction associated with hydrate formation creates a “sink” which drives flow of gaseous and aqueous phases to the hydrate formation zone. Flow driven by saturation gradients plays a key role in creating reservoirs of large hydrate saturations, as observed in Mount Elbert. Viscous-dominated pressure-driven flow of gaseous and aqueous phases cannot explain large hydrate saturations originated from large-saturation gas accumulations. The mode of hydrate formation for a wide range of rate of hydrate formation, rate of descent of the BGHSZ and host sediments characteristics are analyzed and characterized based on dimensionless groups. The proposed transport model is also consistent with field data from hydrate-bearing sand units in Mount Elbert well. Results show that not only the petrophysical properties of the host sediment but also the rate of hydrate formation and the rate of temperature cooling at the surface contribute greatly to the final hydrate saturation profiles. / text

Gas hydrate is a very complicated reservoir system characterized of temperature, pressure, gas composition, pore-water geochemical features, and gas sources, gas hydrate distribution within the gas hydrate stability zone. Temperature, pressure and the gas composition of the sediments were suitable for gas hydrate formation in the gas hydrate reservoir system of Shenhu Area, north slope of South China Sea. The high-resolution seismic data and the gas hydrate drilling getting high concentrations of hydrate (>40%) in a disseminated form in foram-rich clay sediment showed that gas hydrate is distributed heterogeneously at all spatial scales in all drill holes, and the hydrate-bearing sediments ranged several ten meters in thickness are located in the lower part of gas hydrate stability zone (GHSZ), just above the bottom of gas hydrate stability zone (BGHSZ). It is likely seem that the methane to crystallize gas hydrate is from in-situ microbial methane.

The petroleum industry is currently moving to meet the ever-rising demand for oil and gas production. As onshore fields become depleted and decline in production, exploration and production companies have started venturing further offshore. To support this activity, there is need for new subsea production technologies to develop deepwater and ultra deepwater fields.Woodside Hydrocarbon Research Facility (WHRF) at Curtin University of Technology is working on natural gas dehydration processing using gas hydrate technology. Through the studies, a novel gas dehydration process has been developed and now proposed for subsea application. Natural gas dehydration processes generate both a treated dry gas stream and a waste stream of condensate consisting of both hydrocarbons and water. This condensate can be reinjected to the reservoir formation but this is not always economic or practical. Availability of an alternative means of treatment and disposal of the condensate would be advantageous. This study aims to investigate and to provide a basis for the design of such an alternative scheme by constructing a floating separator for the treatment and disposal of waste condensate from subsea dehydration stage.A model was developed to simulate the process of evaporation of condensate from the proposed floating separator. The calculations were performed taken into account zero wind speed and an ambient temperature around 34 C. The simulation results showed that condensate skimming time was found to be 15 days for flowrate (Qin) of 100 bbd associated with specific separator diameter and total height dimensions. By considering the ratio of diameter to total height of 2.5, the floating separator was designed to enhance the evaporation rate and to get overall structure stability due to the mechanical restrictions that might be encountered in the sea.

Gas hydrate is a potential energy source that has recently been the subject of much academic and industrial research. The search for deep-water gas hydrate involves many challenges that are especially apparent in the northwestern Gulf of Mexico, where the sub-seafloor is a complex structure of shallow salt diapirs and sheets underlying heavily deformed shallow sediments and surrounding diverse minibasins. Here, we consider the effect these structural factors have on gas hydrate occurrence in Garden Banks and Keathley Canyon blocks of the Gulf of Mexico. This was accomplished by first mapping the salt and shallow deformation structures throughout the region using a 2D grid of seismic reflection data. In addition, major deep-rooted faults and shallow-rooted faults were mapped throughout the area. A shallow sediment deformation map was generated that defined areas of significant faulting. We then quantified the thermal impact of shallow salt to better estimate the gas hydrate stability zone (GHSZ) thickness. The predicted base of the GHSZ was compared to the seismic data, which showed evidence for bottom simulating reflectors and gas chimneys. These BSRs and gas chimneys were used to ground-truth the calculated depth of the base of GHSZ. Finally, the calculated GHSZ thickness was used to estimate the volume of the gas hydrate reservoir in the area after determining the most reasonable gas hydrate concentrations in sediments within the GHSZ. An estimate of 5.5 trillion cubic meters of pure hydrate methane in Garden Banks and Keathley Canyon was obtained.

The objective of this study is to determine hydrate formation conditions of a multicomponent polymer based drilling fluid. During the study, experimental work is carried out by using a system that contains a high-pressure hydrate formation cell and pressure-temperature data is recorded in each experiment. Different concentrations of four components of drilling fluid, namely potassium chloride (KCl), partially hydrolyzed polyacrylicamide (PHPA), xanthan gum (XCD) and polyalkylene glycol (poly.glycol) were used in the experiments, to study their effect on hydrate formation conditions.