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Chapoy A.,Heriot - Watt University | Chapoy A.,Hydrafact Ltd. | Mazloum S.,Heriot - Watt University | Burgass R.,Heriot - Watt University | And 4 more authors.
Journal of Chemical Thermodynamics | Year: 2012

Monoethylene glycol (MEG) is commonly added in the formulation of hydraulic and drilling fluids and injected into pipelines to prevent the formation of gas hydrates. It is therefore necessary to establish the effect of a combination of salts and thermodynamic inhibitors on gas hydrate equilibria. In this communication, water activity of five ternary solutions (MEG-H 2O-NaCl, MEG-H 2O-CaCl 2, MEG-H 2O-MgCl 2, MEG-H 2O-KCl and MEG-H 2O-NaBr) and four multicomponent solutions have been measured by a reliable resistive electrolytic humidity sensor. We also report new experimental measurements of the locus of incipient hydrate-liquid water-vapour curve for systems containing methane or natural gas with aqueous solution of ethylene glycol and NaCl over a wide range of concentrations, pressures and temperatures. A thermodynamic approach in which the Cubic-Plus-Association equation of state is combined with a modified Debye Hückel electrostatic term is employed to model the phase equilibria. These new data have been used to optimise binary interaction parameters between salts and MEG implemented in the modified Debye Hückel electrostatic term. The model developed has been evaluated using the new generated hydrate data and literature data. Good agreement between predictions of the modified model and experimental data is observed, supporting the reliability of the developed model. © 2011 Elsevier Ltd. All rights reserved.


Chapoy A.,Heriot - Watt University | Chapoy A.,Hydrafact Ltd. | Haghighi H.,Hydrafact Ltd. | Burgass R.,Heriot - Watt University | And 3 more authors.
Journal of Chemical Thermodynamics | Year: 2012

Carbon dioxide coming from capture processes is generally not pure and can contain impurities such as water. In a typical gas sweetening unit, the acid gas stream will be saturated in water. The presence of water in the acid gas stream can result in ice and/or gas hydrate formation and cause blockage. In this communication, new experimental data are reported for the water content of liquid carbon dioxide in equilibrium with hydrates at 13.9 MPa and temperatures range from 253.15 K to 277.15 K. Three different thermodynamic approaches have been employed to investigate the phase behaviour of the (carbon dioxide + water) system: the Valderama-Patel-Teja (VPT) equation of state combined with the NDD mixing rules, the Soave-Redlich-Kwong (SRK) equation of state with the Huron-Vidal mixing rules combined with a modified NRTL local composition model and the Cubic-Plus-Association equation of state. In all cases, the hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. The reliability of the thermodynamic models and approaches were evaluated by using the new data, (vapour + liquid) equilibrium data and phase equilibrium data in the presence of hydrate for both saturated and under-saturated systems. © 2011 Elsevier Ltd. All rights reserved.


Burgass R.,Hydrafact Ltd | Pedersen K.S.,Calsep A/S | Sorensen H.,Calsep A/S
Fluid Phase Equilibria | Year: 2011

Literature data for the hydrate temperature depression by mono-ethylene glycol (MEG) show some scattering and no thermodynamic model has been able to match all of the available data found in the open literature. This paper presents hydrate equilibrium data for a mixture of 88.13mol% methane and 11.87mol% propane with MEG added to the water phase in concentrations from 0 to 60wt%. That particular hydrocarbon mixture was chosen because it with pure water at pressures above 60bar shows hydrate dissociation temperatures above 20°C and because hydrate dissociation temperatures above the freezing point of water are still seen when the aqueous phase contains 50wt% MEG. This range of inhibitor dosage is typical in North Sea pipelines, and for optimal hydrate control it is vital to have high quality experimental data of hydrate equilibrium. Previously published data for the same hydrocarbon mixture as used in this study show a lower hydrate depression by MEG compared to other available data. The new data from this work show that MEG is more efficient as a hydrate inhibitor than the previously published data for the same system has suggested. The new data and earlier MEG inhibition data for other systems can all be modeled within experimental uncertainty using the hydrate model of Munck et al. and a conventional cubic equation of state for the H 2O-MEG component pair. © 2011 Elsevier B.V.


Burgass R.,Heriot - Watt University | Burgass R.,Hydrafact Ltd | Chapoy A.,Heriot - Watt University | Chapoy A.,Hydrafact Ltd | And 3 more authors.
Journal of Chemical Thermodynamics | Year: 2014

The environmental impact of carbon dioxide has led to the need for capture and storage processes. Whenever water is present, at conditions inside the carbon dioxide hydrate stability zone, there is the possibility of hydrate formation which can cause problems such as pipeline restriction and blockage. To avoid such problems it is essential to know how dry the carbon dioxide needs to be. The measurement of the water content of carbon dioxide in equilibrium with hydrates at different temperature and pressure conditions gives a value below which hydrates will not form. There is a scarcity of relevant experimental data especially at low temperatures (<263.15 K). This is in part due to the challenging nature of making accurate equilibrium water content measurements at these conditions. The experimental data can be used to compare with predictions made using different thermodynamic models. This paper presents experimental equipment, methods and results for the water content of carbon dioxide in equilibrium with hydrates at temperatures between (223.15 and 263.15) K and pressures between (1.0 and 10.0) MPa, hence in both vapour and liquid phases. The experimental data are compared with predictions from an in-house (previously developed) thermodynamic model. © 2013 Elsevier Ltd. All rights reserved.


Chapoy A.,Heriot - Watt University | Burgass R.,Heriot - Watt University | Haghighi H.,Hydrafact Ltd. | Tohidi B.,Heriot - Watt University
Society of Petroleum Engineers - SPE Asia Pacific Oil and Gas Conference and Exhibition 2011 | Year: 2011

In this communication we present experimental techniques, equipment and thermodynamic modelling for investigating systems with high CO 2 concentrations, including gas reservoirs with high CO 2 content and/or CO 2-rich systems from capture processes. The experimental equipment consists of high pressure (1,000 bar) equilibrium cells operating over a wide temperature (-80 to 200°C), GC, chilled mirror and Laser Hygrometer for water content measurements. A thermodynamic model based on Cubic-Plus- Association (CPA) equation of state has been used in modelling phase behaviour of CO 2-rich systems. The hydrate-forming conditions are modelled by the solid solution theory of van der Waals and Platteeuw. The reliability of the thermodynamic model was evaluated using vapour - liquid equilibrium data. CO 2 is a partially polar compound present in many hydrocarbon reservoirs. Its concentration in some hydrocarbon reservoirs is very high, demanding accurate experimental data and thermodynamic modelling. Another important application is modelling phase behaviour and properties of CO 2-rich systems from capture processes for transportation and storage. The results show that the developed model, combined with a reliable database, is a powerful tool for modelling complex systems. The resulting thermodynamic model is able to conduct various calculations, including; gas solubilities in aqueous and non-aqueous phases, water content in CO 2-rich systems, hydrate stability zone in the presence of methanol and/or glycols, dehydration requirements for preventing hydrate formation in gas or CO 2-rich phase, and a large number of other calculations. The results of the predictions are compared with experimental data, demonstrating reliability of the techniques developed in this work. CO 2 coming from capture processes is generally not pure and can contain impurities such as water. In a typical gas sweetening unit, the acid gas stream will be saturated with water. The presence of water can result in ice and/or gas hydrate formation at low temperature conditions and cause blockage. Copyright 2011, Society of Petroleum Engineers.


Kazemi A.,Heriot - Watt University | Kazemi A.,Hydrafact Ltd. | Tohidi B.,Heriot - Watt University | Tohidi B.,Hydrafact Ltd. | Nyounary E.B.,Heriot - Watt University
Society of Petroleum Engineers - Offshore Europe Oil and Gas Conference and Exhibition 2011, OE 2011 | Year: 2011

Gas storage and subsequent production is of great interest due to fluctuations in gas demand and the difficulty for large scale gas storage in surface facilities. However, the injection and production of dry gas into or from a depleted gas reservoir could result in serious flow assurance challenges. The injected gas will evaporate connate/formation water to satisfy thermodynamic equilibrium. This will also happen during production phase and may cause salt precipitation, and potentially pore throats plugging. In this paper we quantitatively describe and discuss the parameters involved in water evaporation/production and salt precipitation for a gas production/injection well in a field. In this work, the impact in terms of formation damage (skin) will be evaluated and some recommendations for prediction and mitigation will be proposed. In addition, the water present in the produced gas is a major flow assurance threat due to possibility of gas hydrate formation in the production system. Origin, description, prevention and mitigation methods are discussed and compared. The results show that an increase in the salinity of formation water (due to production) will result in a decrease in the water vapour pressure, hence water vaporization, hence a decrease in the amount of hydrate inhibitor required for preventing hydrate formations in the system. Another important factor observed in this study is capillary pressure. A high capillary pressure will increase the gas/water transient zone and therefore there could be more water production from the well. In addition to water production problem we also observed that due to salt precipitation the porosity and permeability in the vicinity of the wellbore can be reduced by more than 50%. The effect of salt deposition and vaporised water production are potentially serious challenges in gas storage projects. It is necessary to carefully address these challenges in order to make gas storage projects practical and commercial. Copyright 2011, Society of Petroleum Engineers.


Gholinezhad J.,Heriot - Watt University | Chapoy A.,Heriot - Watt University | Haghighi H.,Heriot - Watt University | Haghighi H.,Hydrafact Ltd | Tohidi B.,Heriot - Watt University
73rd European Association of Geoscientists and Engineers Conference and Exhibition 2011: Unconventional Resources and the Role of Technology. Incorporating SPE EUROPEC 2011 | Year: 2011

CO2 capture from CO2/H2 gas mixture is an attractive approach for reducing greenhouse gas emissions. This mixture is associated with power generation processes in power plants and typically contains 40% CO2 and 60% H2. A novel method for capturing CO2 from the above gas mixture is to use gas hydrate formation. This process is based on selective partition of CO2 between hydrate phase and gas phase. Due to their larger diameters, CO2 molecules have higher tendency to go into hydrate clathrates than H2 molecules, which ultimately results in a gas rich in carbon dioxide. This study demonstrates the concept and presents the results of our experimental investigation for CO2/H2 separation by hydrate formation process. Since hydrate formation from water and gas requires high pressures, tetrabutylammonium bromide (TBAB) is added to the system to reduce the equilibrium pressure. TBAB forms semi-clathrates that can encage small gas molecules. The results shows that in one stage of gas hydrate formation and dissociation, CO2 can be enriched from 40% to 88%. In addition, the concentration of CO2 in equilibrium gas phase is reduced from 40% to 18%. While separation efficiency is comparable with the process without any additive, the presence of TBAB improves the operating conditions significantly. In addition, CO2 could be enriched to 98% by two stages of hydrate formation. Copyright 2011, Society of Petroleum Engineers.


Patent
HYDRAFACT Ltd | Date: 2014-08-14

The present invention relates to a method of treating aqueous fluid and apparatus therefor. The method comprises adding an organic compound to a mass of aqueous fluid comprising at least one Kinetic Hydrate Inhibitor (KHI). The organic compound comprises a hydrophobic tail and a hydrophilic head. The hydrophobic tail comprises at least one CH bond and the hydrophilic head comprises at least one of: a hydroxyl (OH) group; and a carboxyl (COOH) group.


Patent
HYDRAFACT Ltd | Date: 2014-08-18

The present invention relates to a method of treating aqueous fluid and apparatus therefor. The method comprises adding an organic compound to a mass of aqueous fluid comprising at least one Kinetic Hydrate Inhibitor (KHI). The organic compound comprises a hydrophobic tail and a hydrophilic head. The hydrophobic tail comprises at least one CH bond and the hydrophilic head comprises a carboxyl (COOH) group.

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