An estimated 1000 trillion cubic meters of gas in the unconventional hydrocarbon resource of gas hydrates in the world?s ocean floors far exceeds the known hydrocarbons in conventional reserves like coal, petroleum, and natural gas. These hydrate deposits also contain massive amounts of the greenhouse gases like methane and carbon dioxide. As relatively little is known about the oceanloor natural gas hydrates, mechanisms leading to the formation of these hydrates in ocean sediments need to be investigated before the significant technical challenges of recovery and environmental hazards are addressed. The subject research focuses on possible catalytic effects of biosurfactants on the formation of natural gas hydrates in oceanloor sediments. Sand/clay packs were saturated with seawater containing 1000 ppm of biosurfactant and pressurized with natural gas of 90 mole% methane, 6 mole% ethane and 4 mole% propane. The experimental results showed that gas hydrates formation in porous media is catalyzed by biosurfactants at very low concentrations. Commercially available representatives from the five biosurfactant classifications that microbes produce were purchased and evaluated in sand/clay packs at hydrateorming conditions. The rate of formation and induction time differed in the presence of bentonite and kaolin. The surface activities of biosurfactants were either specific to sand or clay surfaces. While in the presence of bentonite, Surfactin decreased hydrate induction time by 71% over a reference test with no biosurfactant in the seawater; Surfactin lowered induction time by 25% in the presence of kaolin. Rhamnolipid reduced the induction time by 58% in the presence of bentonite and by 66% in the presence of kaolin. Snomax and Emulsan, belonging to the classification of polysaccharide lipid complexes, reduced induction time by 30 to 40% in the presence of both kaolin and bentonite. Fatty acids reduced the induction time by 55% in the presence of bentonite and by 20% in the presence of kaolin. Surfactin enhanced the rate of formation by 400% in the presence of bentonite, but it had minimal effect in the presence of kaolin. Emulsan and Snomax increased the rate of formation by 250%, while rhamnolipid and phospholipids doubled formation rate in the presence of bentonite. Emulsan increased the rate of formation by 800%. In seawater, at hydrateorming conditions, rhamnolipid was found to have a critical micellar concentration of 12 ppm. This very low value of CMC suggests that minimal bacterial activity in ocean sediments could greatly catalyze hydrate formation. The recent analysis by Lanoil et al. (2001) of sediments from around gas hydrate mounds in the Gulf of Mexico gives a direct association between microbes and gas hydrates and supports the conclusions of the subject work.

One of the new approaches for capturing carbon dioxide from treated flue gas (post-combustion capture) and fuel gas (pre-combustion capture) is based on gas hydrate crystallization. The presence of small amount of tetrahydrofuran (THF) substantially reduces the hydrate formation pressure from a flue (CO2/N2) gas mixture and offers the possibility to capture CO2 at medium pressures [1]. A conceptual flow sheet for a medium pressure hydrate process for pre-combustion capture from a fuel gas (CO2/H2) was also developed and presented. In order to test the hydrate-based separation processes for pre and post combustion capture of CO2 at a larger scale a new apparatus that can operate with different gas/water contact modes is set up and presented.

In 1995, the U.S. Geological Survey made the first systematic assessment of the in-place natural gas hydrate resources of the United States. That study suggested that the amount of gas in the gas hydrate accumulations of northern Alaska probably exceeds the volume of known conventional gas resources on the North Slope. Researchers have long speculated that gas hydrates could eventually be a commercial resource yet technical and economic hurdles have historically made gas hydrate development a distant goal rather than a near-term possibility. This view began to change over the past five years with the realization that this unconventional resource could be developed in conjunction with conventional gas fields. The most significant development was gas hydrate production testing conducted at the Mallik site in Canada’s Mackenzie Delta in 2002. The Mallik 2002 Gas Hydrate Production Research Well Program yielded the first modern, fully integrated field study and production test of a natural gas hydrate accumulation. More recently, BP Exploration (Alaska) Inc. with the U.S. Department of Energy and the U.S. Geological Survey have successfully cored, logged, and tested a gas hydrate accumulation on the North Slope of Alaska know as the Mount Elbert Prospect. The Mallik 2002 project along with the Mount Elbert effort has for the first time allowed the rational assessment of the production response of a gas hydrate accumulation.

The presence of gas hydrates offshore of eastern Canada has long been inferred from estimated stability zone calculations, but the physical evidence is yet to be discovered. While geophysical evidence derived from seismic and borehole logging data provides indications of hydrate occurrence in a number of areas, the results are not regionally comprehensive and, in some cases, are inconsistent. In this study, the results of systematic seismic mapping along the Scotian and Newfoundland margins are documented. An extensive set of 2-D and 3-D, single and multi-channel, seismic reflection data comprising ~45,000 line-km was analyzed for possible evidence of hydrate. Bottom simulating reflectors (including one double BSR) were identified at five different sites, ranging between 300 and 600 m below the seafloor and in water depths of 1000 to 2900 m. The combined area of the five BSRs is 1720 km2, which comprises a small proportion of the theoretical stability zone area along the Scotian and Newfoundland margins (~635,000 km2). The apparent paucity of BSRs may relate to the rarity of gas hydrates on the margin or may be simply due to geophysical limitations in detecting hydrate.

Geochemical processes associated with gas hydrate formation lead to the growth of iron sulphides which have a geophysically-measurable magnetic signature. Detailed magnetic investigation, complemented by petrological observations, were undertaken on cores from a permafrost setting, the Mackenzie Delta (Canadian Northwest Territories) Mallik region, and two marine settings, IODP Expedition 311 cores from the Cascadia margin off Vancouver Island and the Indian National Gas Hydrate Program Expedition 1 from the Bengal Fan. Stratigraphic profiles of the fine scale variations in bulk magnetic measurements correspond to changes in lithology, grain size and pore fluid geochemistry which can be correlated on local to regional scales. The lowest values of magnetic susceptibility are observed where iron has been reduced to paramagnetic pyrite, formed in settings with high methane and sulphate or sulphide flux, such as at methane vents. High magnetic susceptibility values are observed in sediments which contain detrital magnetite, for example from glacial deposits, which has survived diagenesis. Other high magnetic susceptibility values are observed in sediments in which the ferrimagnetic iron-sulphide minerals greigite or smythite have been diagenetically introduced. These minerals are mostly found outside the sediments which host gas hydrate. The mineral textures and compositions indicate rapid disequilibrium crystallization. The unique physical and geochemical properties of the environments where gas hydrates form, including the availability of methane to fuel microbiological activity and the concentration of pore water solutes during gas hydrate formation, lead to iron sulphide precipitation from solute-rich brines. Magnetic surveying techniques help delineate anomalies related to gas hydrate deposits and the diagenesis of magnetic iron minerals related to their formation. Detailed core logging measurements and laboratory analyses of magnetic properties provide direct ties to original lithology, petrophysical properties and diagenesis caused by gas hydrate formation.

Seismic reflection data from a multi-channel streamer deployed offshore Korea reveal evidence of hydrateforming gases being vented into the ocean. Numerous, localised vent structures are apparent from reduced seismic reflection amplitude, high seismic velocities, and reflector pull-up. These structures penetrate upward from the base of the gas hydrate stability zone (GHSZ) and are typically several hundred metres wide, and only a few hundred metres high. Underlying zones of reduced reflection amplitude and low velocities indicate the presence of gas many kilometers below the seabed, which migrates upward through near-vertical conduits to feed the vent structures. Where the local geology and underlying plumbing indicates a high flux of gases migrating through the system, the associated vent structures show the greatest change of reflector pull-up (the greatest concentration of hydrate) to be near the seabed; where the local geology and underlying plumbing indicates a moderate flux of gases, the greatest change of reflector pullup (the greatest concentration of hydrate) is near the base of the GHSZ. The distribution of gas hydrate in the high-flux gas vent is consistent with the recent salinity-driven model developed for a rapid and continuous flow of migrating gas, while the hydrate distribution in the lower-flux vent is consistent with a liquid-dominated system. The high-flux vent shows evidence of recent activity at the seabed, and it is likely that a substantial amount of gas is passing, or has passed, through this vent structure directly into the overlying ocean.

Formations containing gas hydrates are encountered both during ocean drilling for oil or gas, as well as gas hydrate exploration and exploitation. Because the formations are usually permeable porous media, inevitably there are energy and mass exchanges between the water-based drilling fluids and gas hydrates-bearing formation during drilling, which will affect the borehole’s stability and safety. The energy exchange is mainly heat transfer and gas hydrate dissociation as result of it. The gas hydrates around the borehole will be heated to decomposition when the drilling fluids’ temperature is higher than the gas hydrates-bearing formation in situ. while mass exchange is mainly displacement invasion. In conditions of close-balanced or over-balanced drilling, the interaction between drilling fluids and hydrate-bearing formation mainly embodies the invasion of drilling fluids induced by pressure difference and hydrate dissociation induced by heat conduction resulting from differential temperatures. Actually the invasion process is a coupling process of hydrate dissociation, heat conduction and fluid displacement. They interact with each other and influence the parameters of formation surrounding the borehole such as intrinsic mechanics, pore pressure, capillary pressure, water and gas saturation, wave velocity and resistivity. Therefore, the characteristics of the drilling fluids invading into the hydrate-bearing formation and its influence rule should be thoroughly understood when analyzing on wellbore stability, well logging response and formation damage evaluation of hydrate-bearing formation. It can be realized by establishing numerical model of invasion coupled with hydrate dissociation. On the assumption that hydrate is a portion of pore fluids and its dissociation is a continuous water and gas source with no uniform strength, a basic mathematical model is built and can be used to describe the dynamic process of drilling fluids invasion by coupling Kamath’s kinetic equation of heated hydrate dissociation into mass conservation equations.

Discovery of natural methane hydrate in deepwater sediments in the east-coast of India have generated significant interest in recent times. This work puts forward a possible relationship of multi-TCF gas accumulation through destabilization of paleo-hydrate in Plio-Pleistocene deepwater channel sands of Krishna-Godavari basin, India. Analysis of gas in the study area establishes its biogenic nature, accumulation of which is difficult to explain using the elements of conventional petroleum system. Gas generated in sediments by methanogenesis is mostly lost to the environment, can however be retained as hydrate under suitable conditions. Longer the time a layer stayed within the gas hydrate stability zone (GHSZ) greater is the chance of retaining the gas which can be later released by change in P-T conditions due to sediment burial. P-T history for selected stratigraphic units from each well is extracted using 1-D burial history model and analyzed. Hydrate stability curves for individual units through time are generated and overlain in P-T space. It transpired that hydrate formation and destabilization in reservoir units of same stratigraphic level in different wells varies both in space and time. Presence of paleo hydrates is confirmed by the occurrence of authigenic carbonate cement and low-saline formation water. We demonstrate how gas released by hydrate destabilization in areas located at greater water depths migrates laterally and updip along the same stratigraphic level to be entrapped in reservoirs which is outside the GHSZ. In areas with isolated reservoirs with poor lateral connectivity, the released gas may remain trapped if impermeable shale is overlain before the destabilization of hydrate. The sequence of geological events which might have worked together to form this gas reservoir is: deposition of organic rich sediments → methanogenesis → gas hydrate formation → destabilization of hydrate and release of gas → migration and entrapment in reservoirs.

Replacement of the traditional thermodynamic hydrate inhibitors (methanol and glycols) in multiphase applications is highly desirable for Health, Safety & Environment (HSE) considerations and for investment costs savings. Low Dose Hydrate Inhibitors (LDHI) are good candidates to achieve this objective and their interest is growing in the E&P industry. There are two types of LDHI: the Kinetic Hydrate Inhibitors (KHI) and the Anti-Agglomerants (AA) also called dispersant additives. The main challenge with LDHIs is that they require the unprocessed effluents to be produced inside the hydrate stability zone. It is then of the utmost importance to select, qualify and implement properly LDHIs, so that their field deployment is performed with success. But due to the very stochastic nature of the nucleation step, the hydrate crystallisation process leads to very large discrepancies between performances results carried out at lab or pilot scales. In order to overcome this difficulty, we have developed an in-house special protocol which is implemented prior to each qualification tests series. This in-house 15 years old protocol consists in conducting each tests series with a fluids system having previously formed hydrates in a first step but followed by a dissociation step at moderate temperature for a few hours. This paper presents results selected from several field cases studies and obtained from our 80 bara and 165 bara flow loops. They show the very good reproducibility obtained with and without LDHIs. In the case of KHI, where the stochastic nature of the nucleation step is very critical, the results show that the deviation on the “hold time” for a given subcooling is less than 15%. (Revised version of ICGH paper 5499_1)

In this study, we investigated the molecular characteristics of hydrates which were synthesized from gas mixtures containing the two isomers of butane, or the pentane isomers neopentane and isopentane, in excess methane. Thereto various techniques, including Raman spectroscopy, powder and single crystal X-ray diffraction and 13C NMR spectroscopy were employed. It turned out that shape and conformation of the guest molecule and hydrate structure both influence each other. In case of the mixed butane hydrate it could be confirmed that n-butane is enclathrated in its gauche conformation. This was verified by Raman spectroscopy, single crystal X-ray diffraction and calculated data. While isopentane is known as a structure H former, our results from powder X-ray diffraction, 13C NMR and ab initio calculations show that it can be also incorporated into structure II when the hydrate is formed from a neopentane/isopentane/methane gas mixture.