Inhibitor containing systems were investigated for hydrate structures I and II. The kinetic inhibitor PVCap was added to the water phase for each hydrate structure. Dissociation temperatures were determined for various formation temperatures and PVCap concentrations. Obtained dissociation temperatures were compared with corresponding values calculated with CSMHYD. Differences between experimental and calculated values were compared for various formation temperatures and inhibitor concentrations. Comparison revealed that these parameters (formation temperature and concentration) had an effect on the dissociation temperature. Dissociation temperatures for hydrates formed at low degrees of subcooling were higher than for hydrates formed at large subcooling. The effect depended on the system pressure; apparently decreasing or vanishing with increasing pressure. Furthermore, the temperature of dissociation increased with the inhibitor dose.

The kinetic inhibitor Poly Vinyl Caprolactam (PVCap) was added as a kinetic inhibitor to the gas-water system. Different hydrate formers were used in order to obtain formation of the different hydrate structures (sI, sII and sH). All hydrate structures were formed with PVCap. The effect of applying different melting rates was investigated. The isochoric technique was used to obtain dissociation temperatures and corresponding pressures. The melting rate was found to be a parameter influencial for the dissociation temperature. Even for very slow melting rates such as 0.0125 Kelvin per hour, the final dissociation temperature was significantly higher that the dissociation temperature for the corresponding non-inhibited system.

Raman spectroscopic observations of the characteristics and dissociation of methane hydrate were carried out on hydrates synthesized in silica sands with particle sizes of 53-75 μm, 90-106 μm, 106-150 μm, and 150-180 μm. The results obtained indicate that methane hydrates formed in silica sands had similar characteristics regarding cage occupancy and hydration number (5.99) to bulk hydrate, indicative of no influence of particle size on hydrate composition. During hydrate dissociation, the change in average intensity ratio of large to small cages were generally consistent with that of bulk hydrate but dropped dramatically after a certain time, and this turning point seems to be related to the particle size of silica sands.

Methane hydrate formation and dissociation studies from high water content (>60 vol% water) – crude oil emulsions were performed. The hydrate and emulsion system was characterized using two particle size analyzers and conductivity measurements. It was observed that hydrate formation and dissociation from water-in-oil (W/O) emulsions destabilized the emulsion, with the final emulsion formulation favoring a water continuous state following re-emulsification. Hence, following dissociation, the W/O emulsion formed a multiple o/W/O emulsion (60 vol% water) or inverted at even higher water cuts, forming an oil-in-water (O/W) emulsion (68 vol% water). In contrast, hydrate formation and dissociation from O/W emulsions (≥71 vol% water) stabilized the O/W emulsion.

The flow assurance industry is progressively moving away from avoidance of hydrate formation towards risk management. Risk management allows hydrates to form but prevents hydrates from agglomerating and forming a plug, or delays hydrate formation within the timescale of the residence time of the water in the hydrate-prone section of the flow line. A key factor in risk management for an oil-dominated system is the stability of the emulsified water with gas hydrate formation. It is shown using Differential Scanning Calorimetry (DSC) that gas hydrate formation and dissociation has a destabilizing effect on W/O emulsions, and can even lead to a free water phase through agglomeration and coalescence of dissociated hydrate particles. Gas hydrate formation/dissociation has been shown to cause rapid hydrate agglomeration and emulsion destabilization. High asphaltene content crude oils are shown to resist hydrate destabilization of the emulsion.

An understanding of the mechanism for hydrate formation from water-in-oil emulsions is integral for progressing from preventing hydrate formation through expensive thermodynamic means to hydrate blockage prevention. This work presents hydrate formation and agglomeration in a stirred system studied using two complementary particle size analysis techniques, a Particle Video Microscope (PVM) and a Focused Beam Reflectance Measurement (FBRM). The PVM provides qualitative visual information through digital images in the black oil illuminated by a series of lasers. The FBRM provides a quantitative chord length distribution of the particles/droplets in the system. Three sets of experiments were performed using two different Crude oils, Conroe with a very small asphaltene content and poor emulsion stability, and Caratinga with a much higher asphaltene content and emulsion stability. The first experiments looked at ice as an analogy to hydrates, studying the morphology with both the PVM and FBRM. The second experiments looked at the effect of droplet size on hydrate formation and agglomeration, and the third set of experiments studied the dissociation process using a combination of the PVM and in situ conductivity measurements to determine the continuous phase. For hydrate formation, droplet size was found to have a major effect on whether or not agglomeration will occur. During dissociation agglomeration is extremely dramatic due to the creation of surface water on the particles. The dissociation of these agglomerates results in a significant destabilization of the suspension into a water/hydrate phase at the bottom of the cell until dissociation is complete. The dissociation conceptual picture presented illustrates an important implication when operating a flow line with hydrates present; dissociation within the pipeline should be prevented until the hydrates are out of the flow line.

Gas hydrates are crystalline solids (clathrates) in which gas molecules are encaged within lattices of hydrogen bonded water molecules. Hydrates are stable at low temperatures and high pressures; and dissociation takes place at temperatures and pressures outside the stability zone. Modeling the dissociation behavior of hydrates in porous soil media requires attention be paid to the geomechanics of hydrate dissociation. This paper addresses the issue of coupling the hydrate dissociation problem with the soil deformation problem and constructs the mathematical framework. Thermally stimulated dissociation process under undrained conditions is considered with conduction heat transfer.

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.

Design and construction of long term gas hydrate production facilities will require assessment of the in situ formation response to production at a field scale. Key parameters such as temperature and pressure are critical for the determination of phase conditions, others such as formation resistivity, formation acoustic properties and fluid mobility support the inference of gas hydrate saturation, permeability and porosity. An ability to continuously monitor the response of these parameters during the course of a production test would facilitate tracking of the dissociation front and yield valuable information for engineering design and verification of numerical reservoir simulators. Such a monitoring system has been designed, developed and introduced as a part of the Japan Oil, Gas and Metals National Corporation and Natural Resources Canada gas hydrate production testing program carried out in the winter of 2007 in the Mackenzie Delta, Canada. While the deployment of some sensors and the acquisition of some data sets were limited due to operational problems encountered during the field program, considerable experience has been gained during all phases of the research program. In particular, the acquisition and interpretation of downhole temperature profiles and changes in formation electrical potentials during testing provide insight into the production response of the reservoir and may assist in the understanding of operational conditions and related decision-making processes.

This work is part of a research project sponsored by the Italian Electricity Agency for CO2 disposal in form of hydrate. The dissociation behavior of CH4 hydrate was taken as a reference for the study of the CO2 hydrate preservation. The formation and dissociation of CO2 and CO2–THF mixed hydrates, compared to CH4 and CH4 – THF mixed hydrates, has been considered. The experimental tests were performed in a 2 liter reaction calorimeter at pressures between 0.1 and 0.3 MPa. The dissociation has been followed at temperatures from -3 °C to 0 °C for CO2 and CH4 hydrates, and from -3 °C to 10 °C for THF mixed hydrates. More than pressure, which is very important for methane hydrates, temperature affects the preservation of CO2 and CO2–THF mixed hydrates. Subcooling after formation is important for methane hydrate preservation, but it does not substantially affect CO2 hydrate stability. In the studied P, T range, CO2 hydrate does not present any anomalous self-preservation effect. The mixtures containing more ice show a slower dissociation rate. Methane hydrate requires less energy to dissociate than CO2 hydrate and, therefore, is less stable. On the contrary, the mixed CO2 – THF hydrates are less stable than the mixed methane hydrates. Modulated differential scanning calorimetry (MDSC) has been used for hydrate characterization: both CH4 and CO2 hydrates include two decomposition peaks, the first due to the melting of the ice and the second to the decomposition of the hydrate. The higher temperature of the decomposition peak of CO2 hydrate confirms its higher stability respect to CH4 hydrate.