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.

The purpose of this study is to develop the production method of CO2 hydrate-slurry. In this paper, the production process of CO2 hydrates with pure water dissolved antifreeze proteins (AFPs) is discussed. CO2 hydrate-slurry can be transported from a production place to storage one with a small pressure loss. The AFPs have made the hydrate particles be small and well disperse. It is revealed that the Type III AFPs are effective for the inhibition of structure I hydrate production. By the present experiments, the induction time for the hydrate production increases, and moreover the formation rate of the hydrate and the increasing rate of an agitator torque decrease.

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.

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.

The continuous effort to understand the complicated behavior of gas hydrates in multiphase flow has led to the evolution of a new paradigm of hydrate blockage. The hydrate community continues to debate the impact of kinetics, agglomeration, and oil chemistry effects on hydrate blockage formation in pipelines and wellbores. However, today’s industry for the most part still continues to rely on thermodynamic means to develop strategies to prevent hydrates altogether in its production systems. These strategies such as thermal insulation of equipment, electric heating, dead oil displacement, and methanol injection add CAPEX, OPEX, and operational complexities to system design. In spite of high oil prices, adopting such strategies to mitigate perceived hydrate blockage risk can end up taxing economics of marginal fields. Developing a comprehensive multiphase flow simulator capable of handling the transient aspects of production operations - shut-in, restart, blowdown and blockage prediction - continues to drive the research in Flow Assurance. New operating strategies based on risk management approach seem to be evolving from the model predictions. A shift in paradigm that allows for operations inside the hydrate region based on sound risk assessment and management principles could be a factor enabling future developments of marginal fields. This paper discusses the challenges and opportunities that have led to the change in focus from prevention of hydrates to prevention of blockage, and describes some initial successes in the development of a first generation empirical tool for the prediction of hydrate blockages in flow lines. Also presented in this article are new experimental data that shed some light on different ways that hydrate blockages can manifest in the field.

Hydrates in some crude oils have a smaller tendency to form plugs than in others, and lately this is becoming a focus of research. To study this and the action of hydrate antiagglomerants in general, hydrate surface properties must be known. To help in characterizing the surface properties by simulation, the capillary waves of clathrate hydrate surfaces in vacuum are examined in all unique crystal faces by Molecular Dynamics, and an attempt is made to estimate the surface energies in the respective crystal faces from the wave fluctuations [1]. We also attempt to estimate solid/liquid surface energies of hydrate/oil and hydrate/water for a specific face, for comparison. The forcefield OPLS_AA is used for the organic compounds, while TIP4P/ice is used for the water framework. The anisotropy of the surface energy is then estimated and the result compared to the initial growth rate of different crystal faces as found in experiment [2].

Gas hydrates in near-mudline subsea sediments present significant challenges in the production of underlying hydrocarbons, impacting wellbore integrity and placement of subsea equipment. As the fluids of an underlying reservoir flow to the mudline, heat carried by the fluids warms nearwell sediments and dissociates hydrates, which releases gas that can displace and fracture near well soil. This gas release may be calculated with numerical simulations that model heat and mass transfer in hydrate-bearing sediments. The nature and distribution of hydrates within the sediments, the melting behavior of the hydrates, the thermal and mechanical properties of these shallow sediments, and the amount of hydrates contained in the sediments are required for the model simulations. Such information can be costly to acquire and characterize with certainty for an offshore development. In this information environment, it is critical to understand what information, processes, and calculations are required in order to ensure safe, robust systems, that are not overly conservative, to produce the hydrocarbon reservoirs far below the hydrates.

The purpose of the work is to show how to employ the experimental data from geocryology and soil physics for thermodynamic calculations of gas hydrate phase equilibria by taking into account pore water behavior in sediments. In fact, thermodynamic calculation is used here to determine the amount of non-clathrated pore water content in sediments in equilibrium with gas and hydrate phases. A thermodynamic model for pore water behavior in sediments is developed. Taking into account the experimental water potential data, the model calculations show good agreement with the experimentally measured unfrozen water content for different pressure and temperature conditions. The proposed thermodynamic model is applied for calculations of three-phase equilibria: multicomponent gas phase (methane, natural gas, etc.) – pore water in clay, sand, loamy sand, etc. – bulk (or pore) hydrate. As a result, correlations have been established between unfrozen and non-clathrated water content in natural sediments.

A thermodynamic inhibitor - methanol is used for hydrates control both at gas-gathering pipelines and gas conditioning / treatment field plants of Novatek JSC. Due to severe climate conditions and absence of serious infrastructure high operation costs for hydrate control take place. For reducing inhibitor losses some new technological solutions were proposed including recycling and regeneration of saturated methanol. A small module for producing methanol at field conditions was designed. Technological schemes for methanol injection and recirculation are discussed. These technologies reduce methanol losses. Small methanol-producing plant at Yurkharovskoe gas-condensate field (12.5 million ton methanol per year) integrated with field gas treatment plant is presented. The technology includes producing converted gas (syngas) from natural gas, catalytic process for raw methanol synthesis and rectification of raw methanol at final stage. Some particularities of the integrated technology are as follows. Not needs for preliminary purification of required raw materials (natural gas and water). Dried natural gas after conditioning (without any traces of sulfuric compounds) and pure water from simplified water treatment block are used. Rectification of raw methanol is combined with rectification of saturated methanol from gas treatment plant. Economic estimations show that the integrated methanol-producing technology and optimization of methanol circulation in technological processes essentially reduce capital and operational costs for hydrate control at northern gas and gas-condensate fields.

Depressurization is thought to be a promising method for gas recovery from methane hydrate reservoirs, but considerable water production is expected when this method is applied to the hydrate reservoir of high initial water saturation. In this case, the prediction of water production is a critical problem. This study examined relative permeability curves during hydrate dissociation by comparing numerical simulations with laboratory experiments. Data of gas and water volumes produced during depressurization were taken from gas recovery experiments using sand-packed cores containing methane hydrates. In each experiment, hydrates were dissociated by depressurization at a constant pressure. The surrounding temperature was held constant during dissociation. The volumes of gas and water produced, the temperatures inside of the core, and the pressures at the both ends of the core were measured continuously. The experimental results were compared with numerical simulations by using the simulator MH21-HYDRES (MH21 Hydrate Reservoir Simulator). The experimental results showed that considerable volume of water was produced during hydrate dissociation, and the simulator could not reproduce the large water production when we used typical relative permeability curves such as the Corey model. To obtain good matching for the volumes of gas and water produced during hydrate dissociation, the shape of relative permeability curves was modified to express the rapid decrease in gas permeability with increasing water saturation. This result suggests that the connate water can be easily displaced by hydrate-dissociated gas and move forward in the hydrate reservoir of high initial water saturation.