Antonin Chapoy

GAS SEPARATION AND STORAGE USING SEMI-CLATHRATE HYDRATES

Tetra-n-Butyl Ammonium Bromide (TBAB) forms semi-clathrate hydrates which can incorporate small gas molecules, such as methane and nitrogen at ambient temperatures and atmospheric pressure. Such favourable stability conditions, combined with ease of formation could make semi-clathrates particularly attractive for a large variety of applications. These hydrates have recently been investigated for their use in the separation of gases, and it is proposed that the same technology could potentially be used for storage and transportation of gases. To evaluate the feasibility of using TBAB hydrates for separation and storage purposes, an extensive test programme was conducted to determine: phase stability of the semi-clathrates, gas storage capacity, and composition of the stored gas. The results show that TBAB semi-clathrates have very favourable stability conditions. They can store considerable quantities of gas, and favour small molecules in their structures. These experiments suggest that semi-clathrate hydrates, such as TBAB, could have a significant potential as an alternative for industrial separation, storage, and transportation of natural gas.

Hydrates in high MEG concentration systems

Currently the most common flow assurance strategy is to rely upon injection of organic inhibitors, e.g. methanol, monoethylene glycol (MEG) in order to inhibit hydrate formation and to ensure unimpeded flow of hydrocarbons. The current trend for the gas industry is to favour the use of MEG over methanol for new developments. MEG loss to the vapour phase is very small and it has also the advantage that it can be effectively recovered, regenerated and recycled. As exploration and production activities have moved into colder and deeper regions in recent years, higher concentrations of inhibitors are required. The majority of existing data are for inhibitor concentration at or below 50 wt%. Therefore, the industry is demanding data for the conventional inhibitors at higher concentrations. In this communication, we report new experimental dissociation data for various systems consisting of methane and a natural gas at MEG concentration up to 70 wt%. The hydrate dissociation measurements were conducted using standard constant volume (isochoric) technique together with step-heating for achieving equilibrium conditions. A statistical thermodynamic approach, with the Cubic-Plus-Association equation of state, is employed to model the phase equilibria. The hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. A good agreement between predictions and experimental data is observed, supporting the reliability of the developed model.

Thermodynamic conditions and kinetics of integrated methane recovery and carbon dioxide sequestration

Jinhai Yang, Antonin Chapoy, Bahman Tohidi, Prashant Sopanrao Jadhawar, JaeHyoung Lee, Dae Gee Huh

Development of a New Model for Quantifying of Asphaltene Deposition - Role of Precipitation, Aggregation and Radial Transport

Summary Asphaltenes are the heaviest and most polar components of crude oils which are commonly stable in the oil, and can precipitate, aggregate and eventually deposit in reservoirs, flow lines, separators, and other systems along production lines due to changes in conditions such as temperature, pressure and composition. There are a few studies published in the literature focusing on the prediction of asphaltene deposition in pipelines, which reveals that there is lack of a comprehensive deposition simulator which fully considers all effective process during asphaltene deposition phenomena. In this work, a novel framework with considering all effective process in asphaltene deposition was developed and validated to predict the deposition profile of asphaltene during the multiphase flow along the steel tube. Results of this work shows that the asphaltene particles tend to aggregate with each other due to Brownian motion, so the asphaltene deposition model must consider this change in particle size of asphaltenes during the oil flow. It can also be concluded that in addition to the horizontal and vertical flow of oil in the tube, the radial movements of asphaltenes should also be considered to model the asphaltene deposition on the tube surface.

Modeling of Transport Properties Using the SAFT-VR Mie Equation of State

Carbon capture and storage (CCS) has been presented as one of the most promising methods to counterbalance the CO2 emissions from the combustion of fossil fuels. Density, viscosity and interfacial tension (IFT) are, among others properties, crucial for the safe and optimum transport and storage of CO2-rich steams and they play a key role in enhanced oil recovery (EOR) operations. Therefore, in the present work the capability of a new molecular based equation of state (EoS) to describe these properties was evaluated by comparing the model predictions against literature experimental data. The EoS considered herein is based on an accurate statistical associating fluid theory with variable range interaction through Mie potentials (SAFT-VR Mie EoS). The EoS was used to describe the vapor-liquid equilibria (VLE) and the densities of selected mixtures. Phase equilibrium calculations are then used to estimate viscosity and interfacial tension values. The viscosity model considered is the TRAPP method using the single phase densities, calculated from the EoS. The IFT was evaluated by coupling this EoS with the density gradient theory of fluids interfaces (DGT). The DGT uses bulk phase properties from the mixture to readily estimate the density distribution of each component across the interface and predict interfacial tension values. To assess the adequacy of the selected models, the modeling results were compared against experimental data of several CCVrich systems in a wide range of conditions from the literature. The evaluated systems include five binaries (CO2/O2, CO2/N2, CO2/Ar, CO2/n-C4 and CO2/n-C10) and two multicomponent mixtures (90%CO2 / 5%O2 / 2%Ar / 3%N2 and 90%CO2 / 6%n-C4 / 4%n-C10). The modeling results showed low absolute average deviations to the experimental viscosity and IFT data from the literature, supporting the capabilities of the adopted models for describing thermophysical properties of CO2-rich systems

A Novel Technique for Monitoring Hydrate Safety Margin

Great concerns with flow assurance issues have been raised by the oil and gas industry, while the industry is increasingly moving to deepwater reservoirs. Gas hydrate blockages are one of the most common risks for the long distance offshore gas and oil production transport pipelines. Various types of hydrate inhibitors are usually deployed to ensure unimpeded flow of hydrocarbons. At present hydrate inhibitors are injected at the upstream of the pipelines according to approximate assessment of the flowing conditions including the produced water cut and the hydrate phase boundary that is determined based on the worst temperature and pressure conditions, without any means of monitoring the actual degree of inhibition along the pipeline. A novel technique has been developed to optimize the injection of hydrate inhibitors by monitoring the actual hydrate safety margin (i.e., degree of inhibition), which makes it possible to reduce unnecessary cost and potential impact on the environment. It measures the acoustic velocity and electrical conductivity of downstream aqueous samples and then determines both the inhibitor concentration and salt concentration through a trained artificial neural network. The hydrate phase boundary, hence the hydrate safety margin, are finally determined by an integrated in-house thermodynamic model using the determined salt and inhibitor concentrations. Its performance has been intensively evaluated using synthetic samples and real produced water samples by the authors and some oil & gas and service companies. This communication reports the success in development of the hydrate inhibition monitoring system. Results of the evaluation demonstrate that the system can be used for different inhibition systems including methanol-salt systems, mono ethylene glycol- salt systems, and kinetic hydrate inhibitor-salt systems with an acceptable measurement accuracy.

EFFECT OF CLATHRATE STRUCTURE AND PROMOTER ON THE PHASE BEHAVIOUR OF HYDROGEN CLATHRATES

Hydrogen is currently considered by many as the “fuel of the future”. It is particularly favoured as a replacement for fossil fuels due to its clean-burning properties; the waste product of combustion being water. While hydrogen is relatively easy to produce, there is currently a lack of practical storage methods for molecular H2, and this is greatly hindering the use of hydrogen as a fuel. Gases are normally stored in vessels under only moderate pressures and in liquid form where possible, which yields the highest energy density. However, to store reasonable quantities of hydrogen in similar volume containers, cryogenic temperatures or extreme pressure are required. Many potential hydrogen storage technologies are currently under investigation, including adsorption on metal hydrides, nanotubes and glass microspheres, and the chemical breakdown of compounds containing hydrogen to release H2. Recent studies have sparked interest in hydrates as a potential hydrogen storage material. The molecular storage of hydrogen in clathrate hydrates could offer significant benefits with regard to ease of formation/regeneration, cost and safety, as compared to other storage materials currently under investigation. Here, we present new experimental hydrate stability data for sII forming hydrogen–water (up to pressures of 180 MPa) and hydrogen–water–tetrahydrofuran systems, the structure-H forming hydrogen–water– methyclycohexane system, and semi-clathrate forming hydrogen–water–tetra-n-butyl ammonium bromide/tetra–n-butyl ammonium fluoride systems.