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.

In the current work we present a significant advancement in the area of hydrogen storage in clathrates: hydrogen storage from both enclathrated molecular hydrogen as well as storage from the clathrate host lattice. We have investigated the hydrogen storage potential in all of the common clathrate hydrate structures with techniques such as gas evolution, X-ray / neutron diffraction, and NMR / Raman spectroscopy. We have determined that the common clathrate structures may not suffice as H2 storage materials, although these findings will aid in the design and production of enhanced hydrogen storage materials and in the understanding of structure-stability relations of guest-host systems. In view of current storage limitations, we propose a novel chemical – clathrate hybrid hydrogen storage concept that holds great promise for future materials.

Large amounts of CH4 in the form of solid hydrates are stored on continental margins and in permafrost regions. If these CH4 hydrates could be converted into CO2 hydrates, they would serve double duty as CH4 sources and CO2 storage sites. Herein, we report the swapping phenomena between global warming gas and various structures of natural gas hydrate including sI, sII, and sH through 13C solid-state nuclear magnetic resonance, and FT-Raman spectrometer. The present outcome of 85% CH4 recovery rate in sI CH4 hydrate achieved by the direct use of binary N2 + CO2 guests is quite surprising when compared with the rate of 64 % for a pure CO2 guest attained in the previous approach. The direct use of a mixture of N2 + CO2 eliminates the requirement of a CO2 separation/purification process. In addition, the simultaneously-occurring dual mechanism of CO2 sequestration and CH4 recovery is expected to provide the physicochemical background required for developing a promising large-scale approach with economic feasibility. In the case of sII and sH CH4 hydrates, we observe a spontaneous structure transition to sI during the replacement and a cage-specific distribution of guest molecules. A significant change of the lattice dimension due to structure transformation induces a relative number of small cage sites to reduce, resulting in the considerable increase of CH4 recovery rate. The mutually interactive pattern of targeted guest-cage conjugates possesses important implications on the diverse hydratebased inclusion phenomena as clearly illustrated in the swapping process between CO2 stream and complex CH4 hydrate structure.

Evaluation of host geologic sediment interactions with carbon dioxide is very important in sequestration strategies. The objective of the study is to experimentally investigate the effects of different soil mineral types on carbon dioxide hydrate formation. At isothermal, isochoric, and isobaric conditions, batch experiments were conducted with different types of solids (bentonite, kaolinite, nontronite, pyrite, and soil) and electrolytes (NaCl, KCl, CaCl2, and MgCl2) to measure carbon dioxide hydrate formation times. A 50 mL pressurized vessel was used for the experiment by bubbling gaseous CO2 into the solid suspension. We observed that the formation time of carbon dioxide hydrate was dependent on the reactor temperature (273.4 K and 277.1 K) and types of solid and electrolyte. A clear peak was observed in the temperature profile of each experimental run and determined as the hydrate formation time. This is due to the initiation of the hydrate crystallization and latent heat release at the hydrate formation time. The temperature profiles vary significantly with respect to the types of solids and electrolytes. As crystallization initiates, peaks were observed at higher temperatures in pyrite and soil suspensions. The results showed that hydrate formation times for clay minerals in water were approximately twice and 10 times faster than that for pyrite and soil, respectively. The rates of gas consumption were able to be determined by the pressure monitoring. The kaolinite appeared to have the fastest gas consumption rate among the clay mineral suspensions, which was 2.4 times and 7.4 times faster than nontronite and bentonite, respectively. Results from these experiments seem to provide an insight on the formation and growth of carbon dioxide hydrate, once sequestered into the sea bed sediments under the deep sea environment.

Modeling of the onset of permafrost formation and succeeding gas hydrate formation in the changing surface temperature environment has been done for the Beaufort-Mackenzie Basin (BMB). Numerical 1D modeling is constrained by deep heat flow from deep well bottom hole temperatures, deep conductivity, present permafrost thickness and thickness of Type I gas hydrates. Latent heat effects were applied to the model for the entire ice bearing permafrost and Type I hydrate intervals. Modeling for a set of surface temperature forcing during the glacial-interglacial history including the last 14 Myr, the detailed Holocene temperature history and a consideration of future warming due to a doubling of atmospheric CO2 was performed. Two scenarios of gas formation were considered; case 1: formation of gas hydrate from gas entrapped under deep geological seals and case 2: formation of gas hydrate from gas in a free pore space simultaneously with permafrost formation. In case 1, gas hydrates could have formed at a depth of about 0.9 km only some 1 Myr ago. In case 2, the first gas hydrate formed in the depth range of 290 – 300 m shortly after 6 Myr ago when the GST dropped from -4.5 °C to -5.5. °C. The gas hydrate layer started to expand both downward and upward subsequently. More detailed modeling of the more recent glacial–interglacial history and extending into the future was done for both BMB onshore and offshore models. These models show that the gas hydrate zone, while thinning will persist under the thick body of BMB permafrost through the current interglacial warming and into the future even with a doubling of atmospheric CO2.

A HP micro DSC-VII from SETARAM was used to study the efficiency and mechanism of action of commercial kinetic inhibitors for gas-hydrate formation in drilling fluids (OBM). The main objective was to find a suitable and reliable method of screening for these chemicals. The DSC technique consists in monitoring the heat exchanges, due to phase changes (here hydrate formation or dissociation), either versus time at constant temperature or versus temperature during a heating or cooling program. All products showed a gas hydrate dissociation temperature (at a given pressure) that matched with theoretical and previously published data. Nevertheless, for some additives two thermal signals were observed on the thermograms, one that corresponds to the theoretical value and another at a higher temperature (about +4°C). This second peak is insensitive to the heating rate applied for the dissociation, but the areas ratio (1stpeak/2nd peak) changes with the additive concentration and with the driving force applied during the hydrate formation. Additionally, additive/water and additive/water/THF systems were tested. In each case, two dissociation peaks were also measured. The results allow us to disregard any kinetic effects bonded to this thermal phenomenon, and lead us to infer that some additives may induce non-classical crystalline structures of gas hydrates. To verify these results, crystallographic and spectroscopic experiments must be performed. The stabilities of these new compounds are under study.

Simulation of the system behavior of hydrate-bearing geologic media involves solving fully coupled mass- and heat-balance equations. In this study, we develop a domain decomposition approach for large-scale gas hydrate simulations with coarse-granularity parallel computation. This approach partitions a simulation domain into small subdomains. The full model domain, consisting of discrete subdomains, is still simulated simultaneously by using multiple processes/processors. Each processor is dedicated to following tasks of the partitioned subdomain: updating thermophysical properties, assembling mass- and energy-balance equations, solving linear equation systems, and performing various other local computations. The linearized equation systems are solved in parallel with a parallel linear solver, using an efficient interprocess communication scheme. This new domain decomposition approach has been implemented into the TOUGH+HYDRATE code and has demonstrated excellent speedup and good scalability. In this paper, we will demonstrate applications for the new approach in simulating field-scale models for gas production from gas-hydrate deposits.

Hundreds of pockmarks and mounds, which seismic reflection sections show to be underlain by chimney-like structures, exist in southeast part of the Vøring plateau, Norwegian continental margin. These chimneys may be representative of a class of feature of global importance for the escape of methane from beneath continental margins and for the provision of a habitat for the communities of chemosynthetic biota. Thinning of the time intervals between reflectors in the flanks of chimneys, observed on several high-resolution seismic sections, could be caused by the presence of higher velocity material such as hydrate or authigenic carbonate, which is abundant at the seabed in pockmarks in this area. Evidence for the presence of hydrate was obtained from cores at five locations visited by the Professor Logachev during TTR Cruise 16, Leg 3 in 2006. Two of these pockmarks, each about 300-m wide with active seeps within them, were the sites of high-resolution seismic experiments employing arrays of 4-component OBS (Ocean-Bottom Seismic recorders) with approximately 100-m separation to investigate the 3D variation in their structure and properties. Shot lines at 50-m spacing, run with mini-GI guns fired at 8-m intervals, provided dense seismic coverage of the sub-seabed structure. These were supplemented by MAK deep-tow 5-kHz profiles to provide very high-resolution detail of features within the top 1-40 m sub-seabed. Travel-time tomography has been used to detail the variation in Vp and Vs within and around the chimneys. Locally high-amplitude reflectors of negative polarity in the flanks of chimneys and scattering and attenuation within the interiors of the chimneys may be caused by the presence of free gas within the hydrate stability field. A large zone of free gas beneath the hydrate stability field, apparently feeding several pockmarks, is indicated by attenuation and velocity pull-down of reflectors.

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.