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The use of a hydrate-based technology in seawater desalination is an interesting potential hydrate application since salt ions would be excluded from the hydrate crystal lattice. In order to better understand the hydrate-based desalination process, experiments have been conducted using cyclopentane (CyC5, sII) hydrates, which can be formed at atmospheric pressure and temperatures below 7.7 °C. The hydrate formation experiments were performed at various subcoolings for aqueous solutions with different salinities in a bubble column. The hydrate formation times decreased and the hydrate conversion increased with increasing subcooling and agitation. Various hydrate-former injection methods were studied, with the most effective method involving spraying finely dispersed CyC5 droplets (around 5 μm in diameter) into the water-filled bubble column. The latter method resulted in a 2-fold increase in seawater conversion to hydrate crystals compared with injecting millimeter-scale CyC5 droplets. A desalination effic...

There is an interest to ensure sub-saturated water content in lines containing carbon dioxide in applications such as enhanced oil recovery and carbon sequestration, to reduce risks of hydrate blockage and corrosion. The water content of carbon dioxide at various temperatures and pressures has been measured in the past, but there is no consistent set of measurements that could be used for carbon dioxide storage and transportation design work. The solubility of water in a carbon dioxide rich gas phase at hydrate forming conditions was measured in this work. Pressures ranged from 12.06 to 29.30 bar along two isotherms, 1 °C and −7 °C, all within the gaseous carbon dioxide and hydrate stability zone. For the first time in these types of measurements, the solid phase was also characterized and confirmed to be carbon dioxide hydrate via X-ray computed tomography, simultaneous with water content measurements of the gas phase. Once carbon dioxide hydrate conversion had reached a maximum value (65% estimated by X-ray computed tomography), the equilibrium water content was measured. Prior to reaching this maximum carbon dioxide hydrate conversion, the water content in carbon dioxide was observed to decrease as liquid water converted to carbon dioxide hydrate. This slow conversion to hydrate, metastability of the hydrate phase, or unexpected phases may be responsible for the large discrepancy between prior data sets for similar carbon dioxide water content measurements.

The presence of gas hydrates in subsea production is identified as a major flow assurance challenge due to the rapid formation of hydrates and their risk of causing flowline blockages. The risk of hydrate-associated blockages could be higher for transient (shut-in/restart) operations compared to continuous production. Often in offshore production, there are unplanned shut-ins that could lead to increased operational hazards. Despite the practical importance, few studies have addressed the hydrate plugging mechanisms during transient operation. To investigate hydrate transportability in transient operation, tests were performed using an industrial-scale flowloop (3.8 inch in internal diameter and 295 feet in length) with crude oil for a range of water fractions (30–90 vol.%), at 5 wt.% salinity, and across a range of mixture velocities (2.4 -9.4 ft/s). For the tests performed at 50 vol.% water cut (WC) at 5.7 ft/s, the pressure drop and mass flow rate measurements suggest that the transient (or restart, RS) test could result in an earlier onset of hydrate bedding, occurring approximately twice as fast, and may lead to a higher relative pressure drop when compared to the continuous pumping (CP) test. These flowloop experiments suggest that for the RS tests, rapid hydrate formation and agglomeration followed by the water-in-oil (W/O) emulsion destabilization could cause an early increase in pressure drop (and higher operational risks) compared with the CP tests. The tests using an anti-agglomerant (AA) additive (at 1 and 2 vol.%) were performed at 50 vol.% water fraction for all mixture velocities. The tests with an AA indicate that 2 vol. % AA (at all velocities) could prevent hydrate plugging and maintain a slurry flow at 50 vol. % WC for both RS and CP tests. The tests with 1 vol.% AA (at 5.7 ft/s for 50 vol.% WC) show larger fluctuations in pressure drop in the RS test compared to CP tests performed under similar conditions. It is suggested that an improved understanding of hydrate plugging mechanisms during transient operations could help in the development of advanced strategies to manage hydrate transportation in typical subsea operations, particularly involving unplanned shut-ins and subsequent restarts.

Gas hydrates can form in subsea oil and gas flowlines, where the depths of seawater and ocean conditions provide the thermodynamic environment for hydrate stability. Hydrates present a major flow assurance problem due to the relatively fast timescales at which they can form, grow/agglomerate, and plug a flowline. The common strategy for preventing hydrate formation uses thermodynamic inhibitors (THIs). However, THIs can be cost prohibitive or impractical as the water content in the flowline and its seawater depth increases. Therefore, there is growing interest in the use of alternative hydrate management strategies, such as the injection of low dosage hydrate inhibitors (LDHIs), which are active at considerably lower concentrations than THIs (e.g. 2 vol.% of LDHI versus 50 vol.% of THI). Anti-agglomerants (AAs) are a type of LDHI that prevent agglomeration and allow hydrates to flow as a slurry in oil and gas subsea flowlines. Before field deployment, AAs are screened and selected using laboratory set-ups, mimicking field conditions, in order to evaluate their performance and determine the effective dosage. Current hydrate agglomeration characterization methods implemented in the industry are non-uniform and qualitative, which can lead to conservative recommendations. In this work, the possibility of quantifying hydrate agglomeration in the presence of AAs is investigated, along with studies of the mechanisms via which AAs may operate. One mineral oil and two crude oils were used with a commercial AA in a high pressure stirred autoclave, equipped with particle imaging probes. Motor current input at a fixed RPM was monitored throughout the experiments and serves as an indicator of relative viscosity of the hydrate slurry. This investigation enabled the development of a comprehensive AA performance evaluation. Hydrate agglomeration was detected and quantified by simultaneous increases in the relative motor current and chord length distribution.

Clathrate hydrates of hydrogen are of specific interest due to their potential ability to store molecular hydrogen. In particular, structure H (sH) hydrate has a higher theoretical storage capacity in comparison with the other two more common hydrate structures (sI and sII). This paper investigates the effect of hydrogen (H2) concentration on the phase equilibria of sH hydrate in a quaternary system of water, methane, hydrogen, and methylcyclohexane. Phase equilibria and cage occupancies of the quaternary system were predicted using the van der Waals and Platteeuw (vdWP) model for different hydrogen/methane ratios ranging from 0 to 7. Model predictions for the quaternary systems were found to be in good agreement with measured experimental data. It was evident from the thermodynamic equilibrium conditions of the quaternary system (MCH + H2O + CH4 + H2) that as the H2 concentration increases (H2:CH4 ratio increased from 0 to 7), higher pressures are required to produce sH hydrates at the same temperature. It was also found that the fractional cage occupancy of CH4 in the small and medium cages of sH hydrate increases with pressure. Fil: Khan, M. Naveed. Petroleum Institute. Chemical Engineering Department; Emiratos Arabes Unidos. Colorado School of Mines. Chemical & Biological Department. Center for Hydrate Research; Estados Unidos Fil: Rovetto, Laura Jorgelina. Consejo Nacional de Investigaciones Científicas y Técnicas. Centro Científico Tecnológico Bahía Blanca. Planta Piloto de Ingeniería Química (I). Grupo Vinculado al Plapiqui - Investigación y Desarrollo en Tecnología Química; Argentina. Universidad Nacional de Córdoba. Facultad de Ciencias Exactas, Físicas y Naturales; Argentina Fil: Peters, Cor J.. Petroleum Institute. Chemical Engineering Department; Emiratos Arabes Unidos Fil: Sloan, E. Dendy. Colorado School of Mines. Chemical & Biological Department. Center for Hydrate Research; Estados Unidos Fil: Sum, Amadeu K.. Colorado School of Mines. Chemical & Biological Department. Center for Hydrate Research; Estados Unidos Fil: Koh, Carolyn A.. Colorado School of Mines. Chemical & Biological Department. Center for Hydrate Research; Estados Unidos

Hydrogen sulfide is an exceptionally stable structure I (sI) gas hydrate forming guest molecule that is becoming increasingly prevalent in oil and gas production. However, phase equilibria data on pure hydrogen sulfide hydrate reported in the literature are relatively limited and inconsistent compared to other common hydrate formers such as methane or carbon dioxide. In this study, 61 hydrate phase equilibria measurements for sI hydrates containing hydrogen sulfide are reported in the temperature range from T = 273.68 K to 301.53 K and pressure range from p = 0.108 MPa to 1.960 MPa. Experimental data were measured using the isochoric pressure search (IPS) method which has been well established, as well as a modified IPS method, termed the phase boundary dissociation (PBD) method, which gives more efficient measurements of pure hydrate phase equilibria data. For example, it was shown in this work that using the new PBD method reduced the experimental run time to approximately 4.8 h per data point, compared...

When hydrogen (H2) is mixed with small amounts of methane (CH4), the conditions required for clathrate hydrate formation can be significantly reduced when compared to that of simple H2 hydrate. With growing demand for CH4 as a commercially viable source of energy, H2 + CH4 binary hydrates may be more appealing than extensively studied H2 + tetrahydrofuran (THF) hydrates from an energy density standpoint. Using Raman spectroscopic and powder X-ray diffraction measurements, we show that hydrate structure and storage capacities of H2 + CH4 mixed hydrates are largely dependent on the composition of the initial gas mixture, total system pressure, and formation period. In some cases, H2 + CH4 hydrate kinetically forms structure I first, even though the thermodynamically stable phase is structure II.

Clathrate hydrate adhesion forces play a critical role in describing aggregation and deposition behavior in conventional energy production and transportation. This manuscript uses a unique micromechanical force apparatus to measure the adhesion force between cyclopentane hydrate and heterogeneous quartz and calcite substrates. The latter substrates represent models for coproduced sand and scale often present during conventional energy production and transportation. Micromechanical adhesion force data indicate that clathrate hydrate adhesive forces are 5-10× larger for calcite and quartz minerals than stainless steel. Adhesive forces further increased by 3-15× when increasing surface contact time from 10 to 30 s. In some cases, liquid water from within the hydrate shell contacted the mineral surface and rapidly converted to clathrate hydrate. Further measurements on mineral surfaces with physical control of surface roughness showed a nonlinear dependence of water wetting angle on surface roughness. Existing adhesive force theory correctly predicted the dependence of clathrate hydrate adhesive force on calcite wettability, but did not accurately capture the dependence on quartz wettability. This comparison suggests that the substrate surface may not be inert, and may contribute positively to the strength of the capillary bridge formed between hydrate particles and solid surfaces.

Understanding gas hydrate formation on gas bubbles evolved from an oil/gas blowout and the stability conditions of the hydrates formed are key to controlling hydrates during a blowout and its containment. In this work, methane hydrate formation and dissociation conditions on suspended gas bubbles in water were studied. For the formation process, methane gas was gradually injected into a counter flowing water column until a full hydrate shell on suspended gas bubbles was observed. The hydrate shells were then dissociated by either depressurization or heating. The minimum methane concentration to form hydrate shells on suspended gas bubbles in water was determined for the pressure range of (7.0 to 17.3) MPa at 277 K. The dissociation pressures of hydrates are also reported for temperatures from (276 to 286) K. It is observed that the hydrate shells on gas bubbles formed and remained stable only when a minimum dissolved concentration (∼0.0013 mole fraction) of gas in water was reached. During dissociation, h...

We measured cohesion hysteresis between cyclopentane hydrate particles in liquid cyclopentane in the temperature range from −8 to 6 °C. Cohesion hysteresis was small within scatter, and no clear te...

The formation and accumulation of natural gas hydrates in deep subsea flow lines are one of the most challenging flow assurance problems. Typical high pressure/low temperature operation conditions in deep subsea facilities promote rapid formation of gas hydrates. Recent observations in flow loop experiments in gas/water systems suggested a relationship between hydrate volume and flow regime on pressure drop. In the current work, a simple hydrodynamic slug flow model, based on fundamental multiphase flow concepts, is coupled with a transient hydrate kinetics model to study the effect of hydrate formation on slug flow in gas/water systems.

Stable water-in-oil emulsions with water volume fraction ranging from 10 to 70 vol % have been developed with mineral oil 70T, Span 80, sodium di-2-ethylhexylsulfosuccinate (AOT), and water. The mean size of the water droplets ranges from 2 to 3 μm. Tests conducted show that all emulsions are stable against coalescence for at least 1 week at 2 °C and room temperature. Furthermore, it was observed that the viscosity of the emulsion increases with increasing water volume fraction, with shear thinning behavior observed above certain water volume fraction emulsions (30 vol % at room temperature and 20 vol % at 1 °C). Viscosity tests performed at different times after emulsion preparation confirm that the emulsions are stable for 1 week. Differential scanning calorimetry performed on the emulsions shows that, for low water volume fraction emulsions (

As oil/gas subsea fields mature, the amount of water produced increases, which results in an increased risk of gas hydrate plug formation in the flowlines. It is important to understand the mechanism of gas hydrate plug formation in high water cut systems in order to manage gas hydrate risk. In this work, we performed an extensive series of gas hydrate formation and dissociation experiments in a 4-inch diameter flowloop at the ExxonMobil research facility at Friendswood, TX. The flowloop was instrumented for pressure, temperature, density, and differential pressure measurements. The effect of mixture velocity (1–2.5 m/s) and liquid loading (50–90 vol.%) on gas hydrate plug formation was studied for 100 vol.% water cut (no oil present) systems, with methane as the gas hydrate former. The pressure drop across the pump due to flow did not substantially increase until a certain concentration of gas hydrates, defined as ϕ transition , formed; this transition, as measured by the rapid increase in pressure drop, can be used as an indication for onset of hydrate plug formation. ϕ transition was found to be unaffected by liquid loading and the presence of salt (3.5 wt.% NaCl) in water, while it increased with increasing mixture velocity. A gas hydrate plugging mechanism for 100 vol.% water cut systems is proposed, which involves a transition from homogeneous to heterogeneous suspensions of gas hydrate particles in water. We hypothesize that the large pressure drop observed after ϕ transition results from the formation of a gas hydrate bed and wall deposit. A correlation between ϕ transition and the mixture velocity is presented, this correlation allows the prediction of an onset of hydrate plug formation based on the fluids mixture velocity.

One of the major issues in flow assurance includes pipeline plugging due to hydrate formation and deposition. A key uncertainty in gas pipelines is hydrate deposition on the pipe wall. This work demonstrates hydrate formation and deposition on a cold surface in water-saturated gas systems. Methane hydrate deposition can be achieved in a laboratory-scale apparatus by formation of hydrates from the gas phase on the outer surface of a cold surface. The deposit evolves from the initial formation to growth to hardening stages, observed to be initially a porous deposit that later anneals to a relatively nonporous deposit. The hydrate deposit thickness gradually reaches a limit as the hydrate surface approaches the hydrate equilibrium temperature. Performing the measurements at higher initial subcooling in the system results in a thicker hydrate deposit. The average calculated hydrate deposit porosity decreases during the experiment and reaches ∼5% during the annealing stage.

Gas hydrates represent an unconventional methane resource and a production/safety risk to traditional oil and gas flowlines. In both systems, hydrate may share interfaces with both aqueous and hydrocarbon fluids. To accurately model macroscopic properties, such as relative permeability in unconventional systems or dispersion viscosity in traditional systems, knowledge of hydrate interfacial properties is required. This work presents hydrate cohesive force results measured on a micromechanical force apparatus, and complementary water-hydrocarbon interfacial tension data. By combining a revised cohesive force model with experimental data, two interfacial properties of cyclopentane hydrate were estimated: hydrate-water and hydrate-cyclopentane interfacial tension values at 0.32 ± 0.05 mN/m and 47 ± 5 mN/m, respectively. These fundamental physiochemical properties have not been estimated or measured for cyclopentane hydrate to date. The addition of surfactants in the cyclopentane phase significantly reduced the cyclopentane hydrate cohesive force; we hypothesize this behavior to be the result of surfactant adsorption on the hydrate-oil interface. Surface excess quantities were estimated for hydrate-oil and water-oil interfaces using four carboxylic and sulfonic acids. The results suggest the density of adsorbed surfactant may be 2× larger for the hydrate-oil interface than the water-oil interface. Additionally, hydrate-oil interfacial tension was observed to begin decreasing from the baseline value at significantly lower surfactant concentrations (1-3 orders of magnitude) than those for the water-oil interfacial tension.

As oil and gas industry strive for better gas hydrate management methods, there is the need for better understanding of hydrate formation and plugging tendency in a multiphase flow. In this work, an industrial-scale high pressure flowloop was used to investigate gas hydrate formation and hydrate slurry conditions at different flow conditions; fully dispersed and partially dispersed systems. It has been shown that hydrate formation in partially dispersed system can be more problematic as compared to fully dispersed system. For hydrate formation in partially dispersed system, it was observed that there is rapid hydrate growth and rapid increase in pressure drop upon hydrate formation. This is in-contrast to fully dispersed system in which there is gradual increase in the pressure drop of the system. Further, for partially dispersed system, studies have shown that there is hydrate film growth at the pipe wall. This film growth increases the probability of hydrate particle agglomeration and bedding phenomenon, which that lead to flowline plugging. As there is different hydrate formation and plugging mechanism for fully and partially dispersed system, it is thus necessary to investigate and compare systematically the mechanism for both systems. In this project, all experiments were specifically designed to mimic the flow systems that can be found in actual oil and gas pipelines (full and partial dispersion) and understand the transportability of hydrate particles in both systems. Two variables were investigated in this work; amount of water (water cut, WC) and pump speed (fluid mixture velocity). Three different water cuts were investigated; 30, 50 and 90 vol.% water cut. Similarly, three different pump speeds were investigated; 0.91, 1.89, 2.99 m/s. The results from these meausrements were analyzed in terms of relative pressure drop (?Prel) and hydrate volume fraction (fhyd). It was observed that for all water cuts investigated in this work, the ?Prel decreases with increasing pump speed, at a similar hydrate volume fraction. Flowloop plugging occurred for tests with 50 vol.% water cut and pump speeds lower than 1.89 m/s, and for tests with 90 vol.% water cut at a pump speed of 0.91 m/s. Additionally, in all 90 vol.% water cut tests, emulsion breaking where the two phases (oil and aqueous water) separated was observed upon hydrate formation.

Deep subsea facilities with high pressure and low temperature operation, encounter formation of gas hydrates as the most challenging problem in flow assurance. CSMHyK is a transient gas hydrate model specially designed for oil-dominated systems that predicts the formation and transportability of gas hydrates in flowlines. This paper presents a description of three sub-models included in the current version of CSMHyK: kinetics model, transport model and cold flow model; the product of intense efforts over a decade of hydrate research, involving over 20 students at the Center for Hydrate Research at the Colorado School of Mines. A set of conceptual pictures is also presented to describe physical phenomena of gas hydrate formation in water-dominated and gas-dominated systems, as the initial step of a development process that aims to extend CSMHyK towards a comprehensive model, to predict where and when hydrate plugs will form.

Summary A produced-hydrocarbon stream from a wellhead encounters formation of solid gas-hydrate deposits, which plug flowlines and which are one of the most challenging problems in deep subsea facilities. This paper describes a gas-hydrate model for oil-dominated systems, which can be used for the design and optimization of facilities focusing on the prevention, management, and remediation of hydrates in flowlines. Using a typical geometry and fluid properties of an offshore well from the Caratinga field located in the Campos basin in Brazil, the gas-hydrate model is applied to study the hydrate-plugging risk at three different periods of the well life. Additionally, the gas-hydrate model is applied to study the performance of the injection of ethanol as a thermodynamic hydrate inhibitor in steady-state flow and transient shut-in/restart operations. The application of the transient gas-hydrate model proved to be useful in determining the optimal ethanol concentration that minimized the hydrate-plugging risk.

An overview is provided of hydrates in nature manuscripts among the 800 papers of the Seventh International Conference on Gas Hydrates (Edinburgh, July 17–22, 2011), to demonstrate the basic chemico-geophysics, as well as a perspective on hydrates as a resource activity by each country. The following summarizes the current status of gas hydrates as a natural resource: (1) there is substantial methane in hydrates, (2) the most accessible hydrates are in sandy sediments, with lithological controls, (3) laboratory characterization tools are available, (4) field detection tools are acceptable, (5) many of the national programs are in the phase of resource identification and characterization, with two exceptions, and (6) the first long-term production tests of methane hydrates will likely start in 2012 in the North Slope permafrost, and offshore Japan.

Previously, large cage occupancy of H2 has only been confirmed in the structure II (sII) hydrate. Utilizing a hydrate synthesis pathway involving pressurizing preformed structure I (sI) hydrates, we now show H2 occupancy in both the small and the large cages of sI, as evidenced by powder X-ray diffraction and Raman spectroscopic measurements. The new H2 environments were determined to be singly and doubly occupied 51262 cages occurring at 4125–4131 and 4143–4149 cm–1, respectively. This work serves as proof-of-concept that, by altering the conventional hydrate synthesis procedure to incorporate preformed hydrates, it may be possible to promote the occupancy of H2 or possibly other guests in a desired structure through a “templating” effect by simply changing the initial hydrate structure.

The present work uses a micromechanical force apparatus to directly measure hydrate particle–particle cohesion forces in hydrocarbon systems containing various carboxylic acids. Measured cohesive forces provide fundamental insight to the balance between surfactant adsorption kinetics and interfacial thermodynamics in hydrate systems. These results are essential to the accurate prediction of hydrate aggregation in multiphase flow, as encountered in oil/gas production. The present data support the existence of the water capillary bridge between hydrate particles as an essential mechanism for hydrate cohesion in oil continuous systems. The results indicate that, while all surface active compounds tested decreased the water–oil interfacial tension, only some chemicals were effective at reducing the interparticle cohesion force. Through systematic measurements, the data yield new insight into how some acids may alter hydrate surface wettability. Polynuclear aromatic carboxylic acids were found to be highly eff...

Natural gas hydrates are ice-like inclusion compounds that form at high pressures and low temperatures in the presence of water and light hydrocarbons. Hydrate formation conditions are favorable in gas and oil pipelines, and their formation threatens gas and oil production. Thermodynamic hydrate inhibitors (THIs) are chemicals ( e.g., methanol, monoethylene glycol) deployed in gas pipelines to depress the equilibrium temperature required for hydrate formation. This work presents a novel application of a stepwise differential scanning calorimeter (DSC) measurement to accurately determine the methane hydrate phase boundary in the presence of THIs. The scheme is first validated on a model (ice + salt water) system, and then generalized to measure hydrate equilibrium temperatures for pure systems and 0.035 mass fraction NaCl solutions diluted to 0, 0.05, 0.10, and 0.20 mass fraction methanol. The hydrate equilibrium temperatures are measured at methane pressures from (7.0 to 20.0) MPa. The measured equilibrium temperatures are compared to values computed by the predictive hydrate equilibrium tool CSMGem.

Gas hydrates pose a major flow assurance problem in the production and transportation of oil and gas. Managing the formation of gas hydrates is central for safe and continuous operation. In this paper, we will provide an overview of the Center for Hydrate Research and its efforts toward a better understanding of the formation, agglomeration, and accumulation of hydrates in multiphase flow. This paper will discuss the projects in the Center for Hydrate Research aimed at quantifying how hydrates can be managed by first understanding the fundamental processes for nucleation, growth, agglomeration, deposition, and plugging, knowledge in these areas that has been accumulated over decades of research. While still a work in progress, significant advances have been made in describing the hydrate formation in oil-dominated, water-dominated, and gas-dominated systems. One of the end goals of our effort is to develop the knowledge and tools to manage hydrates, as opposed to avoidance, in the production and transport...

Methane hydrate nucleation rates are reported from over 200 μs of molecular dynamics simulations across a range of thermodynamic conditions and varying degrees of methane–water interfacial curvatur...

Effective long-term storage remains a significant challenge to the use and development of protein pharmaceuticals. We have investigated the interactions between clathrate hydrates and model protein solutions to determine the effects on hydrate formation. Here, the dissociation curve and equilibrium conditions for xenon clathrate hydrate with model lysozyme and lactate dehydrogenase (LDH) protein solutions have been studied using calorimetry measurements at pressures ranging from 3 to 20 bar. Sucrose in solution was shown to exhibit small inhibition effects on xenon hydrate formation, shifting the dissociation curve and decreasing the conversion of water to hydrate by 15-26%. The addition of l-histidine buffer and lysozyme at low concentrations did not substantially inhibit hydrate formation. However, small shifts in the dissociation curve were demonstrated for solutions containing LDH. The presence of lysozyme and LDH in solution did not significantly alter the conversion of water to hydrate, indicating that these and similar proteins do not substantially affect the extent of xenon gas hydrate formation. Preliminary experiments were performed for LDH solutions to assess the impact of xenon hydrate formation and dissociation on enzymatic activity, with samples stored in hydrate systems showing small decreases in activity.

Molecular inclusion compounds called clathrate hydrates are a common concern in oil and gas pipelines, as they cause disruption to production. These crystalline compounds are over 80 mol% water and are often only stable at high pressures and low temperatures. As a means to understand the rheology of clathrate hydrates, we investigated ice slurries, in crude oil, as a simple analogy to clathrate hydrates. A series of water-in-oil emulsions were prepared at different volume fractions of water, ranging from 0.10 to 0.70. Water used in the samples was deionized watger or a 3.5 wt% NaCl brine solution. The emulsions were cooled to - 10 ° C and the viscosity and yield stress were analyzed as a function of time after nucleation. No yield stresses were observed at volume fractions below 0.2 for fresh water and 0.3 for brine solution. In the fresh water system, the yield stress varied with increasing volume fraction. Between volume fractions of 0.25–0.55, yield stresses were on the order of 300 Pa, and at larger volumer fractions (0.6–0.7) yield stress quickly increased to an unmeasurable value (greater than 3000 Pa, the instrument’s limit). In the brine system, yield stress increased with volume fraction of water. After formation of ice, flow was stopped and the system was “annealed”. During the “annealing” period, the magnitude of complex viscosity of the fresh water system reached a peak value after two hours, decreased for approximately four hours, and then changed little for the next forty hours. The yield stress during “annealing” mimicked the trend of the magnitude of complex viscosity. In the brine system, the magnitude of complex viscosity increased over the first three hours, then changed little. However, the yield stress decreased as the “annealing” time increased. Following the measurements of yield stress, the slurry was conditioned at 500 s - 1 and the apparent viscosity was analyzed as a function of shear rate. At volume fractions greater than 0.10 the slurry was found to be shear thinning and exhibited a viscosity increase compared to the initial emulsion.

Fundamental understanding of gas hydrate formation and decomposition processes is critical in many energy and environmental areas and has special importance in flow assurance for the oil and gas industry. These areas represent the core of gas hydrate applications, which, albeit widely studied, are still developing as growing fields of research. Discovering the molecular pathways and chemical and physical concepts underlying gas hydrate formation potentially can lead us beyond flowline blockage prevention strategies toward advancing new technological solutions for fuel storage and transportation, safely producing a new energy resource from natural deposits of gas hydrates in oceanic and arctic sediments, and potentially facilitating effective desalination of seawater. The state of the art in gas hydrate research is leading us to new understanding of formation and dissociation phenomena that focuses on measurement and modeling of time-dependent properties of gas hydrates on the basis of their well-established thermodynamic properties.

We present a novel and promising method for the remediation of gas hydrate blockages in oil and gas pipelines, involving purging the gas hydrate plug with nitrogen gas. The resulting lower chemical potential of the hydrate former in the gas phase promotes hydrate dissociation, even though the pressure and temperature remain unchanged. Laboratory measurements on hydrate dissociation enabled the development of a model that estimates the dissociation time for gas hydrate plugs using nitrogen. The hydrate plug dissociation mechanism using a nitrogen purge was shown to involve growing channels and was significantly different from the radial dissociation mechanism observed for the conventional plug depressurization method. The nitrogen purge plug dissociation method provides an important new technology for hydrate plug remediation, in which the hydrate is permeable to gas.

The current paper complements the Moridis et al. (2009) review of the status of the effort toward commercial gas production from hydrates. We aim to describe the concept of the gas hydrate petroleum system, to discuss advances, requirement and suggested practices in gas hydrate (GH) prospecting and GH deposit characterization, and to review the associated technical, economic and environmental challenges and uncertainties, including: the accurate assessment of producible fractions of the GH resource, the development of methodologies for identifying suitable production targets, the sampling of hydrate-bearing sediments and sample analysis, the analysis and interpretation of geophysical surveys of GH reservoirs, well testing methods and interpretation of the results, geomechanical and reservoir/well stability concerns, well design, operation and installation, field operations and extending production beyond sand-dominated GH reservoirs, monitoring production and geomechanical stability, laboratory investigations, fundamental knowledge of hydrate behavior, the economics of commercial gas production from hydrates, and the associated environmental concerns. Introduction Background. Gas hydrates (GH) are solid crystalline compounds of water and gaseous substances described by the general chemical formula G•NH H2O, in which the molecules of gas G (referred to as guests) occupy voids within the lattices of icelike crystal structures. Gas hydrate deposits occur in two distinctly different geographic settings where the necessary conditions of low temperature T and high pressure P exist for their formation and stability: in the Arctic (typically in association with permafrost) and in deep ocean sediments (Kvenvolden, 1988). The majority of naturally occurring hydrocarbon gas hydrates contain CH4 in overwhelming abundance. Simple CH4hydrates concentrate methane volumetrically by a factor of ~164 when compared to standard P and T conditions (STP). Natural CH4-hydrates crystallize mostly in the structure I form, which has a hydration number NH ranging from 5.77 to 7.4, with NH = 6 being the average hydration number and NH = 5.75 corresponding to complete hydration (Sloan and Koh, 2008). Natural GH can also contain other hydrocarbons (alkanes CH2+2,  = 2 to 4), but may also contain trace amounts of other gases (mainly CO2, H2S or N2). Although there has been no systematic effort to map and evaluate this resource on a global scale, and current estimates of in-place volumes vary widely (ranging between 10 to 10 m at standard conditions), the consensus is that the worldwide quantity of hydrocarbon within GH is vast (Milkov, 2004; Boswell and Collett, 2010). Given the sheer magnitude of the resource, ever increasing global energy demand, and the finite volume of conventional fossil fuel resources, GH are emerging as a potential energy source for a growing number of nations. The attractiveness of GH is further enhanced by the environmental desirability of natural gas, as it has the lowest carbon intensity of all fossil fuels. Thus, the appeal of GH accumulations as future hydrocarbon gas sources is rapidly increasing and their production potential clearly demands technical and economic evaluation. The past decade has seen a marked acceleration in gas hydrate R&D, including both a proliferation of basic scientific endeavors as well as the strong emergence of focused field studies of GH occurrence and resource potential, primarily within national GH programs (Paul et al., 2010). Together, these efforts have helped to clarify the dominant issues and challenges facing the extraction of methane from gas hydrates. A review paper by Moridis et al. (2009) summarized the status of the effort for production from gas hydrates. The authors discussed the distribution of natural gas hydrate accumulations, the status of the primary international research and development R&D programs (including current policies, focus and priorities), and the remaining science and technological challenges facing commercialization of production. After a brief examination of GH accumulations that are well characterized and appear to be models for future development and gas production, they analyzed the role of numerical simulation in the assessment of the hydrate production potential, identified the data needs for reliable predictions, evaluated the status of knowledge with regard to these needs, discussed knowledge gaps and their impact, and reached the conclusion that the numerical simulation capabilities are quite advanced and that the related gaps are either not significant or are being addressed. Furthermore, Moridis et al. (2009) reviewed the current body of literature relevant to potential productivity from different types of GH deposits, and determined that there are consistent indications of a large production potential at high rates over long periods from a wide variety of GH deposits. Finally, they identified (a) features, conditions, geology and techniques that are desirable in the selection of potential production targets, (b) methods to maximize production, and (c) some of the conditions and characteristics that render certain GH deposits undesirable for production.

High pressure differential scanning calorimetry was utilized to study the mass transfer rates across methane hydrate films grown at hydrocarbon−water interfaces in a quiescent system, as a function...

Adhesion forces between cyclopentane hydrate particles were measured at atmospheric pressure and 3.2 °C using an improved micromechanical force apparatus. Because of the complexity of crude oil systems, a series of model oils was prepared by adding surface-active components to 200 cP mineral oil as analogues to crude oil systems. The addition of 1 wt % sorbitan monooleate (Span80, a commercial anti-agglomerant), 1 wt % polypropylene glycol (an amphiphilic polymer), and 0.6 wt % commercial naphthenic acid mixture, separately, to a mineral oil and cyclopentane continuous phase, reduced the average interparticle hydrate adhesion force by 37, 65, and 80%, respectively, compared to pure mineral oil and cyclopentane. The 95% confidence bounds of the Span80 and mineral oil data points overlap; therefore, we cannot conclude that Span80 was effective at reducing the adhesion force between hydrate particles. These results indicate that model amphiphilic polymers and commercial naphthenic acid mixtures may be surfac...

Balancing the formation and storage pressure with the storage capacity is one of the most significant steps toward developing H2 storage in hydrates. The large-cage occupancies of hydrogen molecules in tetrahydrofuran (THF), acetone, cyclohexanone (CHONE), and methylcyclohexane (MCH) hydrates were investigated by Raman spectroscopy, volumetric gas release measurement, and X-ray diffraction analysis in a pressure region below the equilibrium pressure of pure H2 hydrates at 255 ± 2 K. The results from the measurements show that H2 molecules occupy the large cage of the structure II THF+H2, acetone+H2, and CHONE+H2 hydrates at the suitable pressures and concentrations of promoter guest species, while H2 molecules do not occupy the largest cage of the structure H MCH+H2 hydrates, even around 70 MPa. The present work reveals that the large-cage occupancy of H2 strongly depends on the pressure and the concentration of promoter guest species. The maximum storage amount of H2 in the acetone+H2 hydrate was 3.6 ± 0...

Three laboratories (Norwegian Institute of Science and Technology [NTNU], Institut Francais du Petrole [IFP], and the Colorado School of Mines [CSM]) determined hydrate plug formation characteristics in three oils, each in three conditions: (1) in their natural state, (2) with asphaltenes removed, and (3) with naturally occurring acids removed from the oil. The objective was to determine the major variables that affect hydrate plugging tendencies in oil-dominated systems, to enable the flow assurance engineer to qualitatively assess the tendency of an oil to plug with hydrates. In the past, it was indicated that chemical effects, for example, water-in-oil/hydrate-in-oil (emulsion/dispersion) stability, prevented hydrate plugs. For example, deasphalted oils provided low emulsion/dispersion stability and thus hydrate particles aggregated. In contrast pH 14-extracted oils were reported to remove stabilizing naphthenic acids, causing asphaltene precipitation on water/hydrate droplets, stabilizing the emulsion...

A review of surface chemistry concepts is presented, with the principal objective of identifying interfacial phenomena and surface chemistry interactions involved in gas hydrate formation and agglomeration in oil and gas pipelines. There are five types of interfaces where gas hydrates may form and aggregate: gas/liquid, liquid/liquid, gas/solid, liquid/solid, and solid/solid; where the gas is the hydrocarbon gas, liquid is either oil, water, or condensate, and solid is either gas hydrate or the pipe wall surface. A review of fundamental interfacial concepts can help create a better understanding of phenomena at these interfaces, and can help industry move from hydrate prevention to risk management. Two areas of surface chemistry have been selected to illustrate the concepts and mechanisms associated with these systems: surfactants and emulsions. Examples from the literature pertaining to gas hydrates are presented for each system.

This work describes the development and application of a transient multiphase flow simulator which incorporates hydrate formation kinetics and thermodynamics to predict plugging in multiphase oil production lines. The model (CSMHyK v. 2.0) is shown to predict the formation of hydrate plugs in two industrial scale flowloops, by combining well known engineering correlations with state-of-the-art measurements. The experimental measurements described here allowed two fitted parameters to be eliminated. Applications of the model are demonstrated by forecasting hydrate formation rates in industrial flowlines. Further developments have allowed hydrate formation in systems with varying concentrations of salt or monoethylene glycol to be simulated by adjusting the hydrate equilibrium P – T curve as the concentration of inhibitor changes.

Water droplet sizes in crude oil emulsions were measured using an in situ particle video microscope (PVM) probe and a focused beam reflectance measurement (FBRM) probe for a variety of oils spanning over two orders of magnitude in viscosity and for varying shear rates. The arithmetic or Sauter mean diameter was found to maintain the same constants of proportionality with the maximum (99th percentile) droplet size for different distributions, previously only shown for water-continuous emulsions. The FBRM values for the mean droplet size, while lower than the PVM values, could be related to the latter by an empirical quadratic relationship with an average error of less than 20%. The droplet size distribution was found to be represented well by a log-normal distribution with good agreement between correlated and measured mean droplet size. Following the agreement between the mean and maximum droplet sizes, the log-normal standard deviation was linearly related to the mean droplet size. The PVM probe was foun...

Cyclopentane (CyC5) hydrate interparticle adhesion force measurements in the presence of small amounts of crude oil (up to 8 wt % in cyclopentane) were performed at 3.2 °C, under atmospheric pressure, using a micromechanical force apparatus. The adhesion forces obtained for cyclopentane hydrate in small amounts of crude oil in CyC5 bulk fluid were lower than those measured for CyC5 hydrate in pure CyC5 bulk fluid. CyC5 hydrate-normalized adhesive forces were measured to be on the order of 0.5 mN/m for samples containing approximately 5−8 wt % of Caratinga and Troika crude. Hydrate-normalized adhesive forces were found to increase when the surface-active components (including acids and asphaltenes) were removed from the crude oil. These results suggest that crude oils with high contents of acids and asphaltenes may be more likely to exhibit nonplugging tendencies in oil and gas flowlines.

Hydrate films typically form at gas−water interfaces where the concentrations of guest and host molecules are the highest. Once formed, the films provide a significant mass transfer barrier to furt...

Summary Gas hydrates (GHs) are a vast energy resource with global distribution in the permafrost and in the oceans. Even if conservative estimates are considered and only a small fraction is recoverable, the sheer size of the resource is so large that it demands evaluation as a potential energy source. In this review paper, we discuss the distribution of natural GH accumulations, the status of the primary international research and development (R&D) programs, and the remaining science and technological challenges facing the commercialization of production. After a brief examination of GH accumulations that are well characterized and appear to be models for future development and gas production, we analyze the role of numerical simulation in the assessment of the hydrate-production potential, identify the data needs for reliable predictions, evaluate the status of knowledge with regard to these needs, discuss knowledge gaps and their impact, and reach the conclusion that the numerical-simulation capabilities are quite advanced and that the related gaps either are not significant or are being addressed. We review the current body of literature relevant to potential productivity from different types of GH deposits and determine that there are consistent indications of a large production potential at high rates across long periods from a wide variety of hydrate deposits. Finally, we identify (a) features, conditions, geology and techniques that are desirable in potential production targets; (b) methods to maximize production; and (c) some of the conditions and characteristics that render certain GH deposits undesirable for production.

SummaryThis work provides a means to predict when and where hydrate plugs will form in oil-dominated flowlines. The method was funded by the DeepStar Consortium of Energy Companies and is based on a Colorado School of Mines hydrate kinetic (CSMHyK) model developed over the last six years, which is currently an addition to the transient multiphase program OLGA by SPT Group Inc. The predictions show good agreement to data for hydrate formation in three flow loops with five oils.Recent CSMHyK-OLGA workshops have been held in Houston (March and April 2007) and Oslo (May 2007), and major companies are beginning to use the program in flow assurance to predict where and when hydrate plugs will form in flowlines.

Economic studies on simulated gas hydrate reservoirs have been compiled to estimate the price of natural gas that may lead to economically viable production from the most promising gas hydrate accumulations. As a first estimate, $CDN2005 12/Mscf is the lowest gas price that would allow economically viable production from gas hydrates in the absence of associated free gas, while an underlying gas deposit will reduce the viability price estimate to $CDN2005 7.50/Mscf. Results from a recent analysis of the simulated production of natural gas from marine hydrate deposits are also considered in this report; on an IROR basis, it is $US2008 3.50–4.00/Mscf more expensive to produce marine hydrates than conventional marine gas assuming the existence of sufficiently large marine hydrate accumulations. While these prices represent the best available estimates, the economic evaluation of a specific project is highly dependent on the producibility of the target zone, the amount of gas in place, the associated geologic and depositional environment, existing pipeline infrastructure, and local tariffs and taxes.

Significant factors controlling gas hydrate growth in water and water-in-oil dispersions have been tested. In particular, the influence of shear rate, presence of oil, and thermodynamic driving force (represented by pressure supersaturation) on hydrate growth rates is included. Formation rates in water show some discrepancy compared to previous work, which is likely caused by differences in the apparatus geometries. A model is proposed for growth of hydrate in oil, in which a hydrate shell forms on a water droplet, followed by additional conversion of the water core to hydrate.

Summary Field data from StatoilHydro on hydrate-plug formation in the Tommeliten gas/condensate field are compared to predictions of the hydrate-growth model (CSMHyK-OLGA) for four typical operating scenarios: steady-state operation with failure of inhibitor injection, restart of an uninhibited line, restart of an underinhibited line, and restart of a depressurized line. Although the CSMHyK model was designed for oil flowlines, the model is able to predict the correct time scale for hydrate-plug formation in this gas/condensate tieback. The predicted locations of the plugs are often farther upstream than observed in the field trials. This is mainly because of the assumption of a "hydrate/oil slip factor" of zero, which forces the hydrate to accumulate where it initially formed. In reality, hydrate agglomerates would be carried further downstream before eventually jamming in dips. Predicting where and when hydrate plugs will form in subsea tiebacks is of increasing importance as the industry strives to manage the risk of plugging in oil and gas flowlines while minimizing the use of costly and environmentally harmful chemicals for hydrate inhibition. The Colorado School of Mines has been developing the CSMHyK model for the past 5 years, in collaboration with the SPT Group and several leading energy companies.

In contrast with the previously accepted paradigm, it is now well established that molecular hydrogen may be contained within the nano-sized cavities of clathrates. Specifically, water-based clathrate hydrates can host a significant amount of H 2 within hydrogen-bonded water cages, with interesting features such as multiple cavity occupation. Additionally, clathrate hydrate analogues have been demonstrated to hold hydrogen and novel hydrogen clathrate materials are continuing to be developed. This work discusses the structures, stabilities, occupancies, and dynamics of hydrogen clathrates and highlights recent developments towards hydrogen storage.

Clathrate hydrates have steadily emerged as an important field in the areas of flow assurance, energy storage and resource, and environment. To better understand the role of hydrates in all of these areas, knowledge developed in laboratory experiments must be effectively transferred to address the challenges related to hydrate formation, dissociation, agglomeration, and stability. This paper highlights the recent hydrate literature focusing on the thermodynamics, kinetics, structural properties, particle properties, rheological properties, and molecular mechanisms of formation. The foundation for continued understanding and development of hydrates in engineering practice will rely on laboratory measurements utilizing traditional and innovative tools capable of probing time-dependent and time-independent properties.