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Foam assisted CO 2 enhanced oil recovery has attracted increasing attention of oil companies (operators and service companies) and research institutions mainly due to the potentially high benefit of foam on CO 2 -EOR. Miscible and immiscible CO 2 flooding projects are respectively proven and potential EOR methods. Both methods have suffered from limited efficiency due to gravity segregation, gas override, viscous fingering and channeling through high permeability streaks. Numerous theoretical and experimental studies as well as field applications have indicated that foaming of CO 2 reduces its mobility, thereby helping to control the above negative effects. However, there are still various conceptual and operational challenges, which may compromise the success and application of foam assisted CO 2 -EOR. This paper presents a critical survey of the foam assisted CO 2 -EOR process to reveal its strengths, highlight knowledge gaps and suggest ways. The oil recovery mechanisms involved in CO 2 foam flood, the effect of gaseous and soluble CO 2 on the process, synergic effect of foaming agent and ultra-low IFT surfactants, logistic and operational concerns, etc. were identified as among the main challenges for this process. Moreover, the complex flow behaviour of CO 2 , oil, micro-emulsion and brine system dictates a detailed study of the physical-chemical aspects of CO 2 foam flow for a successful design. Unavailability of reliable predictive tools due to the less understood concepts and phenomena adds more challenges to the process results and application justifications. The study highlights the recent achievements and analysis about foam application and different parameters, which cannot be avoided for a successful foam assisted CO 2 flood design and implementation. Accordingly, the study also addresses prospects and suggests necessary guidelines to be considered for the success of CO 2 foam projects. SPE 165280sweep efficiency in CO 2 -floods can be high, and the displacement efficiency of a miscible CO 2 flood often exceeds 90%. However, the sweep efficiency of CO 2 processes is often poor. Limitations of the current CO 2 -EORCO 2 would be much more widely used if it were abundantly available (Orr Jr., 2003). Natural sources, by-product of gas treatment units, and combustion processes could be supply sources of CO 2 . However, the present technologies of CO 2 capture and pressurization require energy which would result in a decreased overall energy efficiency and added cost. To recover additional oil in a CO 2 -EOR process, CO 2 is generally injected into the reservoir as a supercritical fluid (Sc-CO 2 ). Sc-CO 2 viscosity is lower than water and most crude oils, which can lead to a number of conformance and mobility issues, and instability in the displacement front, as shown in Fig. 1. Due to the adverse mobility ratio, fingers of CO 2 grow from the displacement front, and cause premature breakthrough, and inefficient CO 2 utilization. Furthermore, the tendency of lower density CO 2 to migrate toward the upper p...

Summary 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%. Introduction 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.