Recent advances in pressure coring techniques, such as the HYACINTH and IODP PCS pressure cores deployed during Expedition 1 of the India National Gas Hydrate Program using the JOIDES Resolution have enabled the recovery of fine grained sediments with intact gas hydrates contained within the sediments. This has provided the opportunity to study the morphology of gas hydrates within fine grained sediments which until now has been hindered due to the long transit times during core recovery leading to the dissociation of the gas hydrates. Once recovered from the seafloor, rapid depressurization and subsequent freezing of the cores in liquid nitrogen has enabled the near complete fine fracture filling nature of the gas hydrates to be largely preserved. High resolution X-ray CT (computer tomography), which has a pixel resolution of approx. 0.07mm, has been used to provide detailed images showing the 3-dimensional distribution of hydrates within the recovered fine grained sediments. Results have shown that in fine grained sediments gas hydrates grow along fine fracture faults within the sediment. Although the fractures were predominantly sub-vertical and continuous through the cores, stranded fractures were also observed suggesting that hydrate formation is episodic. However, within the cores open voids were observed which were not evident in low resolution CT images taken before the depressurization step suggesting that during depressurization either finely disseminated gas hydrate was dissociated or that gas exsolving from solution created these voids in the sample prior to freezing in liquid nitrogen. These detailed observations of gas hydrate in fine grained sediments will help us understand the differing morphology of gas hydrates in sediments. They also show that sample disturbance is still a major concern and further techniques are required to restrict these effects so that meaningful laboratory tests can be undertaken on recovered samples.

A new procedure was studied to obtain concentrated methane hydrates in bulk, at medium-low pressure, avoiding the use of the spray process. Methane hydrate was formed at about 5 MPa and 2 °C in a reaction calorimeter with the volume of two liters. The clathrate concentration was about 30% and the final reactor pressure was 2.7 MPa. Any further repressurization at 2 °C had no noticeable effect on the hydrate formation. However, by repressurizing the vessel again to 4 MPa and increasing the temperature near the decomposition value (about 6° C) more clathrate was formed. Repressurizing again the reactor at 4 MPa and controlling the temperature at the same level, a concentration of 88% hydrate in the bulk was reached. Respect to the hydrate produced by the spray process, this procedure takes more time, but it can be sped up and made continuous by using teo reaction vessels, one for hydrate formation and the other for hydrate concentration. The advantage is the production of concentrated hydrates, by a simple equipment, working at relatively low pressures.

Methane gas hydrates have attracted significant international interest as a potential future energy resource, but also as a geotechnical hazard for offshore operations related to hydrocarbon recovery. In this context, the abilities to detect the presence of hydrate in marine sediments and to quantify the amount of hydrate contained therein, have become increasingly important over the years. Detection and quantification of hydrates are done on the basis of seismic surveys, which measure indirectly the bulk dynamic properties of large volumes of sediment in situ. Seismic data are then interpreted using an effective medium model, which employs theoretical assumptions to relate wave velocities to gas hydrate content of the sediment. Wave velocity can then be used to infer hydrate concentration levels. A host of such effective medium models exists in the literature. Many of these models have been calibrated on and tested on specific sites, and are not readily transferable to other settings. In addition, many models ignore the existence of heterogeneities of the host sediment, or the inhomogeneous distribution of hydrate within it. These, however, are factors that may have a significant impact on the seismic signature of the sediment-hydrate system, and thus on the predicted quantity of hydrate. This paper presents a review of existing effective medium models and identifies general areas for improvement. A new numerical modelling method is outlined that enhances existing effective medium approaches, by taking explicitly into account different hydrate morphologies within the host sediment.

The U.S. Minerals Management Service has completed a preliminary assessment of in-place gas hydrate resources in the Gulf of Mexico. A probabilistic model built on a mass balance approach to assessment provides a high degree of spatial resolution and supports detailed mapping. The model produces a Monte Carlo distribution of in-place resources that ranges from 314 trillion to 974 trillion cubic meters (TCM) with a mean value of 607 TCM. Additional work on development of a technically recoverable model component is under way.

The economic and safety hazards associated with the ability of gas hydrates to form in pipelines have prompted our interest in the inhibition of hydrate growth. Antifreeze proteins (AFPs) adsorb to ice surfaces and certain AFPs can also inhibit the growth of hydrates formed from water molecules organized in cage-like formations around a central small gas molecule. A Monte Carlo computational method for simulating the growth of ice crystals has been developed and it has proved useful in the understanding of the inhibition mechanism of these proteins. We have modified this crystal growth software in order to simulate the growth of large structure II gas hydrates, consisting of millions of water and gas molecules. This represents a first step towards investigating the effectiveness of novel compounds to inhibit hydrate growth in silico. Here, we describe these software modifications, and our efforts to incorporate type I AFP molecules into the hydrate growth simulations. Because both the docking interaction and inhibition mechanism for AFP towards hydrates remains unknown, we have set up a number of inhibitor screens to investigate possible AFP-hydrate docking models. Our goal is to reproduce the changes to gas hydrate morphology that have been observed in the presence of AFP, which will guide our choices for the binding alignment between AFPs and hydrates. This alignment will be instrumental for determining the AFPI-inhibition mechanism and should prove invaluable for the development of novel, hyperactive hydrate inhibitors.

The responsible management and reduction of carbon dioxide (CO2) emissions to the atmosphere requires consideration of alternative options for disposal and long-term sequestration of CO2 generated at hydrocarbon-fueled power plants and large industrial sources. A number of “conventional” options for geological sequestration of CO2 are currently being evaluated worldwide, including disposal of CO2 in depleted oil and gas reservoirs, in deep saline aquifers, and in unrecoverable coal beds, typically in gaseous or liquid form or as a supercritical fluid. Although these geological settings may constitute the most readily accessible sites for immediate utilization, it is unlikely that they represent sufficient cumulative storage capacity to keep pace with global CO2 production and future disposal requirements. In addition, the requirement for long-term maintenance of CO2 sequestered in fluid form, raises concerns regarding the possible mobility of disposed CO2 over the longer term. The Geological Survey of Canada (GSC) has investigated potential opportunities to sequester CO2 in solid form in Canadian geologic reservoirs having pressure and temperature conditions suitable for the formation and long-term stability of CO2 hydrate. Initial screening of candidate reservoirs has identified substantial potentials for CO2 sequestration as gas hydrate in extensive porous sandstone and limestone formations beneath portions of the Canadian Great Lakes, and in areas of the Mackenzie-Beaufort hydrocarbon development region in northern Canada. A significant but less robust capacity has been identified in the oil and gas production regions of northeastern Alberta.

In this work we have formulated the set criteria for cost-effective selection of technologies for industrial production of gas from a hydrate deposit, which rely on the properties of hydrate-bearing rock and the geologic properties of the gas hydrate deposit. For over forty years the world’s energy industry has been trying to effectively master vast unconventional resources of natural gas – the natural gas hydrates [1;3;4]. Specialists have accumulated during this period of time a great deal of knowledge about gas hydrates [8;10]. They established the conditions of hydrate formation in sedimentary rock and the conditions of formation and disappearance of gas hydrate deposits, and offered several classification methods for gas hydrate deposits. Specialists have proposed several methods to locate the gas hydrate accumulations on land and offshore and determined the probable areas where gas hydrate deposits may exist. More than 220 gas hydrate deposits were found to-date, and methods to calculate the amount of gas in a hydrate deposit were developed [1;12]. The principles of gas production from a hydrate deposit were formulated and real experience of commercial natural gas production from a hydrate deposit was gained. However, until now there were no set economic criteria for selection of effective technologies for industrial development of gas hydrate deposits. This results in periodic development of various models not applicable to specific geologic conditions.

A high-resolution seismic reflection survey was conducted during the NT07-05 cruise over the Formosa Ridge offshore southwestern Taiwan where strong and continuous bottom simulating reflections (BSR) have been observed. Previous seafloor pictures taken from a deep-towed camera indicate that there are some chemosynthetic colonies. During the NT07-05 cruise, not only large and dense chemosynthetic communities were confirmed at the plume site, ROV Hyper-Dolphin has also discovered that both deep-sea mussel Bathymodiolus platifrons, and galatheid crab Shinkaia crosnieri are vigorously populated at this site. By integrating swatch bathymetry, multichannel seismic and high-resolution seismic reflection data, we now have a better understanding on the structural characters of the cold seep site. The cold seep is situated at the summit of the Formosa Ridge southern peak. Submarine canyons that incised continental slope on both sides of the ridge are the controlling factors of the ridge formation. The sedimentary strata are generally flat lying but have been deformed by mass wasting processes. Strong BSR is observed 400 to 500 ms below the seafloor of the ridge, with many bright reflections beneath it. There is a narrow vertical blanking zone raising from BSR to the crest of the ridge. This narrow zone is interpreted to be the fluid conduit of the seep site. BSR may form a good cap to trap gas below, and this “gas reservoir” is shallower than the canyon floors on either side of the ridge. We suggest that this “ridge type” gas reservoir configuration enables the cold sea water to get into the fluid system, and forms a special kind of “hydrothermal” circulation that feeds the unusual chemosynthetic communities observed at the Formosa Ridge cold seep site.

The global estimates of methane stored in gas hydrates varied from 1018 to 1015 m3 over the last 4 decades. Each geoscientific discipline has its own quantification methods. The aim of the presented project is the combination of a well proven geochemical approach with a geophysical approach. A transfer function is presented which allows estimations based on geochemical and geophysical parameters. A first application of this combined approach has been performed along seismic line BGR99-44 off Costa Rica. The resulting concentration profile shows a differentiated distribution of the gas hydrate concentration along the slope of the margin with variations of 0 to 3 vol.% of pore space.

Gas hydrate has been identified by drilling in Alaminos Canyon block 818, within the Perdido Fold Belt, outboard of the Sigsbee Escarpment, in approximately 2750 meters (9000 feet) of water. At the location of the AC818 #1 (“Tigershark”) well, the gas hydrate occurs within the top 20 m (65 feet) of an approximately 90 meter (300 feet) thick Oligocene Frio sand, a volcaniclastic sandstone rich in lithic fragments, feldspar, and volcanic ash. The Frio reservoir is folded into a 4-way closed anticline. At the crest of the anticline, the sand is partly eroded and is unconformably overlain by 450 m (1500 feet) of Pleistocene shale and sand. The unconformity surface is also in a 4-way closed geometry and defines the top of the hydrate reservoir at the well. The rock is poorly consolidated and has porosity as high as 42% from log data. LWD logs indicate that the hydrate zone has high resistivity and high P-velocity (2750 mps: 9000 fps). The underlying wet sand at the base of the gas hydrate stability zone (GHSZ) has low resistivity and P-velocity (Vp: 1500 mps: 5000 fps). The very low Vp indicates the presence of low-saturation free gas ("fizz gas"). The large velocity contrast creates a strong response in seismic data which was inverted into a 3D gas hydrates saturation (Sgh) volume. Elsewhere in the GHSZ, seismic character was used to predict predominant sediment facies. Relative high stand facies, which are more clay-rich, will generally be characterized by more continuous and parallel seismic reflectors. In contrast, relative low stand facies, which have more sand content, will be characterized by more hummocky, discontinuous seismic character and will often lie on erosional surfaces, particularly in uncompacted sediments. Understanding the stratigraphy throughout the section is important, since sand will often provide beneficial reservoir conditions, while clay will provide more impervious sealing qualities. The seismic interpretation also identifies migration pathways, such as faults and gas chimneys, and the presence of available gas, which are necessary to charge reservoirs within the HSZ.