Measurement and Prediction of Salt Solubility in the Presence of Hydrate Organic Inhibitors
- Rahim Masoudi (National Iranian Oil Co.) | Bahman Tohidi (Heriot-Watt University) | Ali Danesh (Heriot-Watt University) | Adrian C. Todd (Heriot-Watt University) | Jinhai Yang (Heriot-Watt University)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2006
- Document Type
- Journal Paper
- 182 - 187
- 2006. Society of Petroleum Engineers
- 1.6 Drilling Operations, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 1.8 Formation Damage, 4.3.4 Scale, 4.3.1 Hydrates, 4.2.4 Risers, 5.9.1 Gas Hydrates, 5.2.1 Phase Behavior and PVT Measurements, 5.4.2 Gas Injection Methods, 4.1.5 Processing Equipment, 3.2.6 Produced Water Management, 5.2 Reservoir Fluid Dynamics, 4.2 Pipelines, Flowlines and Risers, 2.1.7 Deepwater Completions Design, 5.2.2 Fluid Modeling, Equations of State, 4.1.2 Separation and Treating, 4.3 Flow Assurance
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Organic inhibitors (e.g. methanol, ethanol, ethylene glycol, and triethylene glycol) are generally used to reduce the risk of gas hydrate formation in drilling and production operations. The addition of organic inhibitors has a significant adverse effect on the solubility of salts, increasing the risk of salt deposition. A better understanding of salting-out problems is necessary for effective design and implementation of flow assurance strategies in such complex systems.
In this paper, we present an experimental investigation on the effect of methanol, ethanol, and ethylene glycol on the solubility of several salts, including halite, sylvite, and antarcticite. The results show that ethylene glycol has a much lesser adverse impact on salt deposition than methanol and ethanol. The details of an experimental setup used for measuring salt solubility and salting out are described. The setup could also provide valuable information on the effectiveness of various inhibitors used for preventing salt deposition in the presence or absence of gas hydrate organic inhibitors.
In addition, a novel predictive numerical approach is proposed to model salt formation in brine solutions with or without hydrate organic inhibitors. The model is based on the equality of the fugacity of salt in the solid phase and aqueous phase, which are calculated by an equation of state. The validity of the new developed model is demonstrated over a wide temperature range (i.e., -20 to 125°C), salt concentration up to saturation point, and hydrate inhibitor concentration up to 50 mass%.
Flow assurance is an essential aspect of safe and economical production of hydrocarbons over the lifetime of a field. Gas hydrate and scale control are two of the key aspects of flow assurance.
Gas hydrates, or clathrates, are icelike crystalline compounds consisting of low molecular diameter gases inside cavities formed by water molecules, which can form at certain pressure and relatively low temperature conditions. Gas hydrate formation is particularly troublesome for offshore drilling and production because of low seabed temperature, high residence time, and high operating pressure. Hydrates can block pipelines and subsea transfer lines and, in the event of a gas kick during drilling, form in the wellbore, risers, blowout preventers (BOPs), and choke lines (Barker and Gomez 1989). Common practice for preventing gas hydrate formation involves the injection of a large quantity of thermodynamic inhibitors (e.g., methanol, ethanol, ethylene glycol, or triethylene glycol). However, the addition of organic inhibitors may adversely affect salt solubility in the associated brine solutions, which often contain high concentrations of dissolved minerals, leading to potential salt precipitation, commonly termed "salting out?? (Kan et al. 2002; Matthews et al. 2002). The deposition of salt may result in flow restriction due to salt-plug formation, as well as hydrate formation (as a result of neglecting the effect of salt deposition on reducing the overall hydrate prevention characteristics of the system).
In the open literature, there is a little information on the solubility of mineral salts in hydrate organic inhibitor/water/salt solutions, which is only applicable to the studied systems and limited range of temperature and pressure (Kan et al. 2002; Tomson et al. 2003; Masoudi et al. 2004a; Pinho and Macedo 1996), and no accepted methodology for correlating the effects of hydrate organic inhibitors on scale formation/inhibition. Therefore, a better experimental and theoretical understanding of the salt formation as a function of both electrolyte and organic inhibitor concentrations in the presence or absence of scale inhibitors over a wide range of temperature and concentration is crucial to the success of any flow assurance strategy.
The work in this communication is the result of a systematic experimental and modeling investigation on the effect of three hydrate organic inhibitors (i.e., methanol, ethanol, and ethylene glycol) on various mineral salt solubility (i.e., halite, sylvite, and antarcticite) over a wide range of temperature and concentration. The applied experimental setup and its capability in determining salt solubility data in the presence or absence of hydrate organic inhibitor are first described. The development of a new thermodynamic approach capable of predicting salt formation in electrolyte solutions with or without hydrate organic inhibitors is then detailed for the studied systems in this work.
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