This contribution aims to publicize the efforts made in the identification of gas hydrates in the Uruguayan continental shelf, analyze the most outstanding aspects related to its energy potential, as well as include this topic in other areas of knowledge for a comprehensive understanding of the subject. The hydrates, crystalline solid formed mainly by water and natural gas, are reservoirs of carbon that occur naturally in the continents in permafrost areas, and at sea, in the offshore basins of continental margins. They contain more than twice the total carbon in the world, surpassing the conventional hydrocarbon reserves. Principal energy programs foresee its commercial exploitation by 2015. International research programs include not only the energy aspect, but studying such systems considering their participation in the global carbon cycle, climate change and benthic communities associated with them. In our country, several seismic surveys showed evidence of the presence of gas hydrates in continental shelf and the surrounding area. The first survey was carried out by Brazil in the south of the Brazilian continental shelf, ANCAP then showed the continuity of the hydrate layer on the Uruguayan continental shelf and estimated the gas potential of the mineralized layer (87 TCF). Finally, the BGR survey verified the existence of seismic evidence of gas hydrates layer and the presence of free gas below these. The typical seismic response of gas hydrate and free gas is the BSR (Bottom Simulating Reflector) and is interpreted as a positive intensity reflection, followed by a negative intensity, showing the wave passage from a high acoustic impedance zone to a low acoustic impedance zone.

A hydrate plugging and formation model for oil and gas pipelines is becoming increasingly important as producers continue to push flow assurance boundaries. A key input for any hydrate plugging model is the rate of hydrate growth and the volume fraction of hydrate at a given time. This work investigates a fundamental approach toward predicting hydrate growth and volume fraction in a water saturated gas pipeline. This works suggests that, in the absence of free water, hydrate volume fraction can be predicted using a wall growth and sloughing model. Wall growth can be predicted using a one-dimensional, moving boundary, heat and mass transfer model. It is hypothesized that hydrate sloughing can be predicted when a coincident frequency exists between hydrate natural frequency and flow induced vibrations over the hydrate surface.

The avoidance of hydrate blockages in deepwater subsea tiebacks presents a major technical challenge with severe implications for production, safety and cost. The successful prediction of when and where hydrate plugs form could lead to substantial reductions in the use of chemical inhibitors, and to corresponding savings in operational expenditure. The diffusivity of the gas hydrate former (methane) or the host molecule (water), through a hydrate film is a key property for such predictions of hydrate plug formation. In this paper, a novel application of Differential Scanning Calorimetry is described in which a hydrate film was allowed to grow at a hydrocarbon-water interface for different hold-times. By determining the change in mass of the hydrate film as a function of hold-time, an effective diffusivity could be inferred. The effect of the subcooling, and of the addition of a liquid hydrocarbon layer were also investigated. Finally, the transferability of these results to hydrate growth from water-in-oil emulsions is discussed.

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.

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.

Using a combination of micromechanical force and flowloop measurements, hydrate deposition on a pipe wall surface was investigated for ‘dry’ hydrates formed in the bulk phase and for hydrates growing on the pipe surface. Cyclopentane ‘dry’ hydrates (without a free water phase) were used to predict whether hydrates, formed in a bulk condensate phase, would adhere to a pipe wall. Adhesion forces between cyclopentane hydrates and steel were measured using a micro-mechanical force apparatus. The average force of adhesion was measured to be very small, less than 0.01 N/m. This force was used in a particle force balance, predicting that hydrates formed in the bulk phase would not deposit on the pipe wall. It was hypothesized than in the presence of a water saturated hydrocarbon, hydrates would grow on the pipe wall as the fluid cooled below its equilibrium temperature. This hypothesis was confirmed using a single pass condensate flowloop. Water was continuously dissolved into the flowloop inlet stream as water deposited in the flowloop test section, resulting in both a pressure drop and fluid temperature increase. This work illustrates the need for a hydrate wall growth model.

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.

An understanding of the blockage potential for an oil dominated system is an important step in moving from hydrate prevention to hydrate management. To better understand this problem a series of experiments were performed by varying the water cut, fluid velocity, and gas-liquid volume fraction using the ExxonMobil (XoM) flow loop in Houston, Texas, USA. The XoM large loop is a three pass, four inch internal diameter flow loop with a sliding vane pump capable of generating liquid velocities of up to 4 m/s. The systems that were studied include a range of water cuts from 5%-50% in a light crude oil (Conroe crude) and a gas phase of either pure methane for sI or 75% methane and 25% ethane which has sII as the thermodynamically stable phase. The results are compared with the hydrate plug prediction tool, CSMHyK, integrated into the multiphase flow simulator OLGA5®. The comparison between the model and the flow loop results serve as a basis for improving hydrate formation and plug prediction. In addition, the experimental variables that promote plug formation in the flow loop and how these may translate into the field are discussed.

Micromechanical adhesion force measurements were performed on tetrahydrofuran (THF) hydrate particles in n-decane. The experiments were performed at atmospheric pressure over the temperature range 261–275 K. A scoping study characterized the effects of temperature, anti-agglomerants, and interfacial energy on the particle adhesion forces. The adhesion force between hydrate particles was found to increase with temperature and the interfacial energy of the surrounding liquid. The adhesion force of hydrates was directly proportional to the contact time and contact force. Both sorbitan monolaurate (Span20) and poly-N-vinyl caprolactam (PVCap) decreased the adhesion force between the hydrate particles. The measured forces and trends were explained by a capillary bridge between the particles.