Hydrate Formation Rate Research Articles

Assessing the Alkyl Chain Effect of Ammonium Hydroxides Ionic Liquids on the Kinetics of Pure Methane and Carbon Dioxide Hydrates

In this study, four ammonium hydroxide ionic liquids (AHILs) with varying alkyl chains were evaluated for their kinetic hydrate inhibition (KHI) impact on pure carbon dioxide (CO2) and methane (CH4) gas hydrate systems. The constant cooling technique was used to determine the induction time, the initial rate of hydrate formation, and the amount of gas uptake for CH4-AHILs and CO2-AHILs systems at 8.0 and 3.50 MPa, respectively, at 1 wt.% aqueous AHILs solutions. In addition, the effect of hydrate formation sub-cooling temperature on the performance of the AHILs was conducted at experimental temperatures 274.0 and 277.0 K. The tested AHILs kinetically inhibited both CH4 and CO2 hydrates at the studied sub-cooling temperatures by delaying the hydrate induction time and reducing the initial rate of hydrate formation and gas uptake. The hydrate inhibition performance of AHILs increases with increasing alkyl chain length, due to the better surface adsorption on the hydrate crystal surface with alkyl chain length enhancement. TPrAOH efficiently inhibited the induction time of both CH4 and CO2 hydrate with an average inhibition percentage of 50% and 84%, respectively. Tetramethylammonium Hydroxide (TMAOH) and Tetrabutylammonium Hydroxide (TBAOH) best reduced CH4 and CO2 total uptake on average, with TMAOH and Tetraethylammonium Hydroxide (TEAOH) suitably reducing the average initial rate of CH4 and CO2 hydrate formation, respectively. The findings in this study could provide a roadmap for the potential use of AHILs as KHI inhibitors, especially in offshore environs.

Formation and dissociation behaviors of SF6 hydrates in the presence of a surfactant and an antifoaming agent for hydrate-based greenhouse gas (SF6) separation

Sulfur hexafluoride (SF6), the most potent greenhouse gas, should be separated from gas mixtures for recycling and for mitigation of global warming. In this study, the formation and dissociation behaviors of SF6 hydrates in the presence of a surfactant (sodium dodecyl sulfate, SDS) and an antifoaming agent (antifoam A concentrate, AAC) were investigated, with a primary focus on kinetic, spectroscopic, and morphological analyses for hydrate-based SF6 separation. The optimum concentrations of SDS and AAC for SF6 hydrates were found to be 250 ppm and 1,500 ppm, respectively. The structure of SF6 hydrates in the presence of SDS and AAC was identified as structure II, indicating that SDS and AAC had no impact on hydrate structure. The formation behaviors of SF6 hydrates were thoroughly examined through gas uptake measurements, visual observation, and in-situ Raman spectroscopy. The addition of SDS 250 ppm significantly accelerated the formation rate of SF6 hydrate and the additional injection of AAC did not inhibit the promoting effect of SDS. Visual observation, temperature profiles, and volume of retrieved gas during the dissociation of SF6 hydrates clearly demonstrated that SDS also had a promoting effect on SF6 hydrate dissociation and its effect was slightly diminished with the addition of AAC, although AAC showed a powerful defoaming effect during the dissociation of SF6 hydrates. The experimental results obtained in this study will be very useful for accelerating the formation rate of SF6 hydrates using SDS and for solving the foaming problem using AAC in the design and operation of the gas hydrate-based SF6 separation process.

Effect of a weak electric field on THF hydrate formation: Induction time and morphology

The kinetics of bulk hydrate formation is of crucial importance in the application of hydrate-based technique involving energy storage, desalination and flow assurance. Various procedures have been found to significantly impact the kinetics of hydrate formation; yet with few studies touching the effects of a weak electric field. A voltage across the solution could likely affect the activity and orientation of the molecules inside, thereby playing a potential role in the hydrate nucleation, crystal growth and even diffusion of water and guest molecules. In this study, the effect of a weak electric field on the induction time, bulk surface characteristics and growth rate of THF (tetrahydrofuran) hydrate were investigated by controlling the voltage across the two electrodes placed on the two sides of the reactor. The results showed that an increasing voltage intensity could result in a longer induction time of hydrate formation. The memory effect was fading at an increasing voltage intensity, indicating that the relic components helping the fast formation could be destroyed by the electric field. The following formation under the electric field can be identified by a neat zigzag surface of hydrate generated from the periphery of the reactor. The formation rate of THF hydrate was found to increase with a rising voltage intensity during the hydrate growth period. The results could be of help in the application of hydrate-based techniques in industries where a fast and successive hydrate growth is expected.

Kinetic analysis of nano-SiO2 promoting methane hydrate formation in porous medium

Natural gas hydrates are abundant and occur globally. The storage and transportation of natural gas in the form of hydrates is considered to be an efficient method limited by low formation rates. In this study, the kinetic effects of SiO2 nanofluids and porous medium on hydrate formation were studied by using magnetic resonance imaging (MRI) technology. The SiO2 nanofluid concentration was varied from 0.1 to 0.4 wt% to analyze its influence. The results showed that hydrates formed near the wall and grew into pores with sufficient water. The concentration variation study revealed a significant decrease in induction time and increase in gas consumption during hydrate formation. Among the various concentrations studied, 0.2 wt% had the strongest promoting effect, and the induction time was shortened by 75.7%, while the gas consumption was 67.7% higher than that in pure water at an initial water saturation of 30%. Concentrations of 0.1–0.3 wt% positively influenced the hydrate formation rate, but a concentration of 0.4 wt% significantly inhibited hydrate formation. In addition, hydrate formation was affected by the initial water saturation of the porous medium. The lower the initial water saturation was, the more notable the promotion effect was. This study provides theoretical support for the storage and transportation of natural gas by combining porous medium and nanofluids.

Generation laws and distribution characteristics of carbon dioxide hydrate in a reaction kettle

We analyzed the generation characteristics of hydrate in a reaction kettle and established a convection–diffusion model of temperature and carbon dioxide. The concentration of liquid carbon dioxide and carbon dioxide dissolved in water were geometrically modeled according to the density of carbon dioxide and its solubility in water under varying temperature and pressure. The distributions of temperature, carbon dioxide and hydrate were analyzed in the reactor during hydrate formation. The factors affecting carbon dioxide hydrate formation were studied. Simulations of hydrate formation were verified by laboratory tests. The results showed that the convective diffusion of gas greatly increased the rate of hydrate formation. Temperature has a greater impact than matter transfer on hydrate formation. At the initial reaction time, the hydrate mainly existed at the boundary, the two-phase interface and the position of the liquid carbon dioxide. Hydrate finally formed in the middle and was thinnest at the interface. The solid–liquid surface tension caused the liquid water to move upward and form hydrates in the carbon dioxide phase. Hydrate formation at the interface between the initial carbon dioxide and water prevented carbon dioxide from diffusing further into the aqueous phase, which hindered further hydrate formation.

Improving gas hydrate-based CH4 separation from low-concentration coalbed methane by graphene oxide nanofluids

This paper reports an investigation of using graphene oxide (GO) nanofluids to improve CH4 separation from low-concentration coalbed methane (LCCBM) via gas hydrate formation. The effect of GO nanofluids on LCCBM purification was evaluated by performing experiments at different concentrations of graphene oxide nanoparticles (GONs) and operation pressures. It was found that both the rates of hydrate formation and gas consumption were enhanced when graphene oxide nanoparticles were added to the liquid phase. Moreover, CH4 separation efficiency was greatly increased as compared to the systems without GONs. With the elevation of operation pressure, the hydrate formation kinetics was enhanced but the CH4 separation efficiency was reduced. The experimental conditions of 286.6 K, 2.0 MPa, and 500 ppm GONs were preferred for CH4 separation from LCCBM. The energy consumption for gas compression and system cooling at this temperature and pressure condition is lower than other LCCBM purification systems reported in the literature. The CH4 concentration in LCCBM was increased from 30 mol% to 76 mol% after two-stage hydrate-based separation. Therefore, the GO nanofluids have a great potential to improve the kinetics of hydrate formation as well as the purification efficiency of LCCBM.

Gas Flow by Invasion Percolation Through the Hydrate Stability Zone

AbstractWe describe gas flow through the hydrate stability zone as a growing gas network with hydrate forming on its edges. The diffusion‐limited model successfully describes the dynamics of hydrate formation observed experimentally. We obtain an expression for the rate of hydrate growth in a region where gas and water coexist. Our modeled rate of hydrate formation is much lower than predicted with a kinetics‐based approach, and it more successfully simulates the hydrate formation rate observed in geologic systems. Current simulation approaches can readily incorporate our approach to describe hydrate formation in geological systems.

Experimental Investigation of Methane Hydrate Formation in the Carboxmethylcellulose (CMC) Aqueous Solution

Summary In the development of deepwater crude oil, gas, and gas hydrates, hydrate formation during drilling operations becomes a crucial problem for flow assurance and wellbore pressure management. To study the characteristics of methane hydrate formation in the drilling fluid, the experiments of the methane hydrate formation in water with carboxmethylcellulose (CMC) additive are performed in a horizontal flow loop under flow velocity from 1.32 to 1.60 m/s and CMC concentration from 0.2 to 0.5 wt%. The flow pattern is observed as bubbly flow in experiments. The experiments indicate that the increase of CMC concentration impedes the hydrate formation while the increase of liquid velocity enhances formation rates. In the stirred reactor, the hydrate formation rate generally decreases as the subcooling condition decreases. However, in this work, with the subcooling condition continuously decreasing, hydrate formation rate follows a “U” shaped trend—initially decreasing, then leveling out and finally increasing. It is because the hydrate formation rate in this work is influenced by multiple factors, such as hydrate shell formation, fracturing, sloughing, and bubble breaking up, which has more complicated mass transfer procedure than that in the stirred reactor. A semiempirical model that is based on the mass transfer mechanism is developed for current experimental conditions, and can be used to predict the formation rates of gas hydrates in the non-Newtonian fluid by replacing corresponding correlations. The rheological experiments are performed to obtain the rheological model of the CMC aqueous solution for the proposed model. The overall hydrate formation coefficient in the proposed model is correlated with experimental data. The hydrate formation model is verified and the predicted quantity of gas hydrates has a discrepancy less than 10%.

Evaluation on the natural gas hydrate formation process

Abstract Gas hydrates have endowed with great potential in gas storage, and rapid formation of gas hydrates is critical to use this novel technology. This work evaluated the natural gas hydrate formation process, which was compared from six parameters, including conversion of water to hydrate, storage capacity, the rate of hydrate formation, space velocity (SV) of hydrate reaction, energy consumption and hydrate removal. The literature was selected by analyzing and comparing these six parameters mentioned above, meanwhile placing emphasis on the three parameters of storage capacity, the rate of hydrate formation and space velocity of hydrate reaction. Through analysis and comparison, four conclusions could be obtained as follows. Firstly, the overall performance of the stirring process and the spraying process were better than other processes after analyzing the six parameters. Secondly, the additive types, the reactor structure and the reactor size had influence on the natural gas hydrate formation process. Thirdly, the energy consumption via reciprocating impact in the hydrate formation process was higher than that via stirring, spraying and static higee. Finally, it was one key for hydrate removal to realize the hydrate industrial production.

Methane hydrate formation in a water-continuous vertical flow loop with xanthan gum

Hydrate phase transition in drilling fluid is a non-ignorable problem for developing deep-water oil, natural gas and natural gas hydrate resources. Once gas hydrates form during drilling, it will increase the difficulty of wellbore pressure management and flow assurance, which enlarges the risk of hydrate blockage and causes serious property damage and casualties. Methane hydrate formation experiments are conducted in xanthan gum (XG) aqueous solution to mimic the drilling fluid flowing condition in a vertical flow loop. The experiments reveal that the hydrate formation process is a mass transfer process and experiences four different hydrate formation periods, because of the kinetics formation and slough of hydrate shells. The subcooling temperature has a weaker impact on the hydrate formation than the flow velocity and XG. The increase of flow velocity can enhance the hydrate formation rate in drilling fluid but the increase of XG concentration can inhibit the hydrate formation. The influence mechanisms of hydrate shell kinetic slough, flow velocity and XG concentration on hydrate formation are analyzed and discussed in detail. We built a mass-transfer hydrate formation model based on the mechanism of methane molecule diffusing from gas phase to liquid phase. The empirical overall mass transfer coefficient is introduced involving the influence of hydrate shell kinetic slough, flow velocity and XG concentration. In model validation, the maximum discrepancy of the developed model decreases from 146.85% to 11.03% after using the overall mass transfer coefficient.

Predictive modeling of thermogenic methane hydrate formation and geobody distribution – Results from numerical simulations

Reservoir characterization of thermogenic gas hydrates have so far been limited to seismic mapping, well log interpretation, and lab scale experiments, with numerical modeling mostly focusing on gas production from hydrates. What is unknown however is the hydrate saturation at the sub-seismic and interwell scales. This study uses numerical simulations for predictive modeling of hydrate formation and geobody distribution using TOUGH + Hydrate. Results indicate that the flow of gas is buoyancy and advection dominated, and affects hydrate formation rate and saturation distribution. Geological controls such as fault angles, stratigraphic thickness, permeabilities and permeability anisotropies and contrasts with adjacent formations significantly impact distribution of hydrate saturation, and geobody shape. Hydrates form in both high and low porosity rocks. While full-scale reservoir modeling is contingent upon the availability of detailed reservoir and fluid data, this study underscores the importance of using numerical modeling tools for quantitative predictive modeling and reservoir characterization of hydrate reservoirs for better resource estimation, well-placement decisions, reservoir management and production planning.

Kinetics features of natural gas hydrates crystallisation and dissociation in water/crude oil and water/asphaltene-resin-paraffin deposit emulsions

The crystallisation and dissociation of natural gas hydrates synthesised in paraffin oil emulsions of the Irelyakh deposit (Eastern Siberia) and in emulsions of asphaltene-resin-paraffin deposits (ARPDs) originated from this oil have been studied with application of high-pressure differential scanning calorimetry (HP DSC). Crystallisation of hydrate-containing phase in the water-in-ARPD (W/ARPD) emulsions with formation of natural gas hydrates enriched with methane and ethane has been defined to proceed much slower than the rate of formation and composition of hydrates formed in water-in-oil (W/O) emulsions. The hydrates grow better in emulsified water droplets than in bulk water, while the hydrate content decreases with increase of water cut in W/O emulsion, and a slower rate of hydrate formation in the W/ARPD emulsion, as compared with W/O emulsion, leads to a greater conversion of water droplets into hydrate phase. It has been shown that more stable hydrates are formed in W/ARPD. [Received: September 9, 2017; Accepted: February 13, 2018]

Kinetics features of natural gas hydrates crystallisation and dissociation in water/crude oil and water/asphaltene-resin-paraffin deposit emulsions

The crystallisation and dissociation of natural gas hydrates synthesised in paraffin oil emulsions of the Irelyakh deposit (Eastern Siberia) and in emulsions of asphaltene-resin-paraffin deposits (ARPDs) originated from this oil have been studied with application of high-pressure differential scanning calorimetry (HP DSC). Crystallisation of hydrate-containing phase in the water-in-ARPD (W/ARPD) emulsions with formation of natural gas hydrates enriched with methane and ethane has been defined to proceed much slower than the rate of formation and composition of hydrates formed in water-in-oil (W/O) emulsions. The hydrates grow better in emulsified water droplets than in bulk water, while the hydrate content decreases with increase of water cut in W/O emulsion, and a slower rate of hydrate formation in the W/ARPD emulsion, as compared with W/O emulsion, leads to a greater conversion of water droplets into hydrate phase. It has been shown that more stable hydrates are formed in W/ARPD. [Received: September 9, 2017; Accepted: February 13, 2018]

Geological sequestration of CO2 in a water-bearing reservoir in hydrate-forming conditions

Higher concentration of carbon dioxide in the atmospheric air is a major environmental challenge and requires immediate attention for quicker mitigation. In that respect, the novel idea of CO2 sequestration in geological settings is worth examining from a quantitative perspective. In the present study, numerical simulation of CO2 injection into a porous reservoir is performed. The selected reservoir presents suitable thermodynamic conditions for CO2 hydrate formation. Unsteady simulations are carried out in one space dimension under isothermal and non-isothermal frameworks. An additional simulation of CO2 injection in a depleted methane hydrate reservoir is also reported. In the present study, the response of the reservoir to storage of CO2 is analyzed with respect to four parameters – reservoir porosity, initial water saturation and reservoir temperature and injection pressure. Quantities of interest are hydrate formation patterns and the cumulative CO2 mass sequestration in the reservoir as a function of time. Numerical experiments show that the initial water saturation is an important parameter as it affects both CO2 gas migration and hydrate formation. Isothermal simulation yields results that are similar to the non-isothermal model, thus suggesting that the isothermal assumption may be adopted for future CO2 injection studies. Hydrate formation rate of CO2 near the injection well is found to be one order of magnitude higher than the interior but its magnitude is quite small when compared to water and gas saturations. Higher injection pressure leads to a continuous increase in injected mass of CO2 primarily due to increased gas density, though an increase in hydrate formation near the injection well is also observed. Lower reservoir temperature supports a higher amount of hydrate formation from the injected mass of CO2 and is clearly desirable.

Geomechanical effects of carbon sequestration as CO2 hydrates and CO2-N2 hydrates on host submarine sediments

Over the past 10 years, more than 300 trillion kg of carbon dioxide (CO2) have been emitted into the atmosphere, deemed responsible for climate change. The capture and storage of CO2 has been therefore attracting research interests globally. CO2 injection in submarine sediments can provide a way of CO2 sequestration as solid hydrates in sediments by reacting with pore water. However, CO2 hydrate formation may occur relatively fast, resulting decreasing CO2 injectivity. In response, nitrogen (N2) addition has been suggested to prevent potential blockage through slower CO2-N2 hydrate formation process. Although there have been studies to explore this technique in methane hydrate recovery, little attention is paid to CO2 storage efficiency and geomechanical responses of host marine sediments. To better understand carbon sequestration efficiency via hydrate formation and related sediment geomechanical behaviour, this study presents numerical simulations for single well injection of pure CO2 and CO2-N2 mixture into submarine sediments. The results show that CO2-N2 mixture injection improves the efficiency of CO2 storage while maintaining relatively small deformation, which highlights the importance of injectivity and hydrate formation rate for CO2 storage as solid hydrates in submarine sediments.

Chemical Affinity Modeling of Methane Hydrate Formation and Dissociation in the Presence of Surfactants

Methane hydrate formation and dissociation and its kinetics after addition of sodium dodecylbenzenesulfonate (SDBS), cetyltrimethylammonium bromide (CTAB), and Tergitol in the aqueous phase were investigated experimentally along with its storage capacity. The experiments were carried out with surfactant concentrations varying between 0 and 10 000 ppm in the aqueous phase. The nucleation temperature, pressure, dissociation temperature and point, pressure drop, formation rate, and storage capacity were significantly changed by the addition of surfactants in the aqueous phase during hydrate formation and dissociation. Maximum subcooling was required for nucleation after addition of 5000 ppm SDBS. The hydrate formation rate and rate constants were found to increase with the addition of surfactants, while the same were reduced with time. The formation rate increased 443-fold after addition of 10 000 ppm SDBS in the aqueous phase. The maximum storage capacity was found at 1000 ppm SDBS in the aqueous phase, which then decreased with a further increase in concentration. The chemical affinity model was developed for hydrate formation and dissociation and was employed successfully. Chemical affinity, thermodynamic extent of reaction, and affinity decay rates were calculated using the pressure and temperature data from the hydrate formation and dissociation trace with time. Affinity decay rates were increased after addition of surfactants, and the maximum was observed after addition of 1000 ppm SDBS in the aqueous phase. These results suggested that the surfactants, SDBS, CTAB, and Tergitol, improved the hydrate formation and dissociation effectively. The chemical affinity model can be efficiently employed for a better understanding of the hydrate formation and dissociation kinetics along with thermodynamics.

Application of hydrophobic particles in the formation kinetics of methane hydrate in water-in-oil emulsion

Aiming at the problem of natural gas hydrate blockage inside oil and gas pipelines, the key to reasonably suppress the formation of hydrates in pipelines is to find the factors that cause the hydrates to coalesce quickly. Since carbonates and silicon-containing substances are the main components of impurities in mining, the formation of methane hydrate has been studied. The emulsion was formulated with Span85 and SDS, and the formation rate and growth morphology of the hydrate were studied by adding nano-calcium carbonate. Experiments were carried out on emulsion systems having a particle content ranging from 0.1 wt% to 6 wt%. The results show that when the particle content in the system is low (less than 0.3 wt%), the hydrate formation rate is accelerated; when the particle content is high (above 2 wt%), the hydrate formation rate is lowered. This phenomenon was confirmed by calculating the moles consumption of methane gas. Moreover, the particles increase the collision probability of the crystal nucleus in the system, and can be used as a nucleation site of the hydrate crystal nucleus. The promotion or inhibition of the system on hydrate growth has reference value for preventing pipeline blockage.

In-situ observation for natural gas hydrate in porous medium: Water performance and formation characteristic

Extensive efforts have been made regarding gas hydrate sample reconstruction in the laboratory for a better understanding and development of natural gas resources. Magnetic resonance imaging (MRI) is a useful method for directly observing the reconstruction of methane hydrate, yet relevant studies remain limited. In this study, a 9.4-T 400-MHz MRI instrument was employed to investigate CH4 hydrate formation in porous media involving various initial water saturation levels and sand diameters. Pressure histories and MRI signal variations were monitored to discuss the process of CH4 hydrate growth, and the three main formation stages of induction, rapid growth, and slow formation were determined. Furthermore, the liquid water performance in MRI micro-images was analyzed to predict the characteristics of CH4 hydrate formation. The results indicated that CH4 hydrate formed in a spatially and temporally random manner and that pore plugging occurred owing to the residual water encased in grown hydrate. Additionally, phase saturations, water conversion percentages, and formation rates were defined to evaluate the effect of sand diameter and initial water saturation on CH4 hydrate formation. With the reduction in the diameter of quartz glass beads from 400 μm to 100 μm, the average hydrate formation rate increased from 0.0010 min−1 to 0.0034 min−1, respectively. When the initial water saturation decreased to the optimized value (0.22 in this study), the water conversion percentage and hydrate saturation increased.

Innovative Approach To Enhance the Methane Hydrate Formation at Near-Ambient Temperature and Moderate Pressure for Gas Storage Applications

The solidified natural gas (SNG) technology via hydrates is a promising and potential method for storing natural gas. It offers a compact mode of natural gas storage with high degree of safety. In this work, we present the synergistic effects of tetrahydrofuran (THF), hollow silica (HS), and sodium dodecyl sulfate (SDS) in enhancing the kinetics of mixed methane–THF hydrate formation at 6 MPa and 293.2 K in an unstirred reactor configuration. HS at the low loading of 0.5% w HS/v in 5.56 mol % THF solution used in the current study is an innovative approach to improve the surface contact area resulting in kinetic enhancement at moderate conditions (low driving force). However, the mixture of 0.5% w HS/v in 5.56 mol % THF solution resulted in a long induction time (about 400 min), which is not favorable for the SNG technology. Addition of SDS decreased the induction time and increased the hydrate formation rate under similar experimental conditions. The induction time significantly decreased with the increase in the SDS concentration. Additionally, the presence of SDS played a key role in influencing the temperature profile and the hydrate morphology during mixed hydrate formation. The methane gas uptake was 0.0591 (±0.0007) and 0.0615 (±0.0023) mol of methane/mol of water without and with SDS, respectively. Thermal stimulation with ΔT = 15 K was employed to recover methane from hydrates. A recovery of 96–98% of the stored methane gas from the hydrates formed with and without SDS was demonstrated. Interestingly, the presence of HS was effective in preventing the foam generation during hydrate dissociation in the presence of SDS.

Memory Effect in Methane Hydrate Formation

Memory effect of formation water in methane hydrate formation and reformation is investigated in a high pressure reactor. Methane hydrate formation rates in fresh water and reacted water are measured at different pressures and temperatures. A significant reduction in formation time and incubation period is found with reused water. In the context of transportation of natural gas from distant gas fields as hydrate, this information can be utilized to reduce reduce the transportation cost of natural gas.