Subsurface Carbon Dioxide Sequestration and Storage in Methane Hydrate Reservoirs Combined With clean Methane Energy Recovery

The authors gratefully acknowledge the financial support (2003-2005) received from the Scottish Higher Education Funding Council. Thanks to Mr. Jim Pantling for construction and maintenance of the experimental equipment. Prashant Jadhawar thanks the Institute of Petroleum Engineering and the Centre for Gas Hydrate Research for financial support. Useful comments from Ross Anderson and Rod Burgass are also gratefully acknowledged.Peer reviewedPostprin

Prediction of methanol content in natural gas with the GC-PR-CPA model

International audienceProduced reservoir fluids are principally composed of hydrocarbons but contain also impurities such as carbon dioxide, hydrogen sulphide and nitrogen. These fluids are saturated with the formation water at reservoir conditions. During production, transportation and processing ice and/or gas hydrates formation may occur. Gas hydrate and ice formation are a serious flow assurance and inherently security issues in natural gas production, processing and transport. Therefore, inhibitors are usually injected as a hydrate inhibitor and antifreeze. For example, methanol is often used for hydrate inhibition or in some cases during start up, shut down or pipeline plug removal. Therefore impurities, water and methanol usually end up in natural gas conditioning and fractionation units. These units produce end user pipeline gas subject to local specifications and natural gas liquids like ethane, LPG or heaviers. This is why the accurate knowledge of methanol content at different operating conditions is important. In this study, a group contribution model, the GC-PR-CPA EoS (Hajiw et al., 2015) (Group Contribution – Peng-Robinson – Cubic-Plus-Association), is successfully applied for hydrocarbons systems containing methanol. Predictions of phase envelopes of binary systems as well as partition coefficients of methanol in hydrocarbons mixtures are in good agreement with experimental data

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

International audienceCarbon capture and storage (CCS) has been presented as one of the most promising methods to counterbalance the CO 2 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 CO 2-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 CO 2-rich systems in a wide range of conditions from the literature. The evaluated systems include five binaries (CO 2 /O 2 , CO 2 /N 2 , CO 2 /Ar, CO 2 /n-C 4 and CO 2 /n-C 10) and two multicomponent mixtures (90%CO 2 / 5%O 2 / 2%Ar / 3%N 2 and 90%CO 2 / 6%n-C 4 / 4%n-C 10). The modeling results showed low percentage absolute average deviations to the experimental viscosity and IFT data from the literature, endorsing the capabilities of the adopted models for describing thermophysical properties of CO 2-rich systems

Thermophysical Properties, Hydrate and Phase Behaviour Modelling in Acid Gas-Rich Systems

International audienceIn this communication we present experimental techniques, equipment and thermodynamic modelling for investigating systems with high acid gas concentrations and discuss experimental results on the phase behaviour and thermo-physical properties of acid gas-rich systems. The effect of high CO 2 concentration on density and viscosity were experimentally and theoretically investigated over a wide range of temperature and pressures. A corresponding-state model was developed to predict the viscosity of the stream and a volume corrected equation of state approach was used to calculate densities. The phase envelope and the hydrate stability (in water saturated and under-saturated conditions to assess dehydration requirements) of some acid gas-rich fluids were also experimentally determined to test a generalized model, which was developed to predict the phase behaviour, hydrate dissociation pressures and the dehydration requirements of acid gas rich gases

Experimental and modelling study of the densities of the hydrogen sulphide + methane mixtures at 253, 273 and 293 K and pressures up to 30 MPa

International audienceDensities of three binary mixtures of hydrogen sulphide and methane (xH 2 S + (1-x) CH 4), with mole fractions of 0.1315, 0.1803 and 0.2860 of acid gas, were determined experimentally at three temperatures (253, 273 and 293) K and at pressures up to 30 MPa. Densities were measured continuously using a high temperature and high pressure Vibrating Tube densitometer (VTD), Anton Paar DMA 512. The SAFT-VR Mie, PR and GERG2008 equations of state (EoS) are used to describe the experimental data with different levels of success