More than 90% of Brazilian oil and gas reserves lie in offshore fields and over 60% of the total reserves are located in deep and ultradeep waters. Some of the important technical problems associated with deep and ultradeep water drilling involve:
low formation fracture gradients;
long choke lines; and
low temperatures at the mud line.
The well control planning and strategy for drilling exploratory and development wells in those fields should address those technical drawbacks in order to achieve the safety requirements in a cost-effective scenario. The better understanding of gas solubility in synthetic based drilling fluids plays a fundamental role in terms of preventive (kick detection) and corrective (kick circulation out of the hole) well control practices. The present work involves PVT characterization of two organic liquids (n-paraffin and ester) currently applied in drilling fluid systems for deep and ultradeep water drilling, in Campos Basin (Rio de Janeiro, Brazil). The measurement of thermodynamical properties of the methane-liquid mixtures, such as bubble point pressure, solubility, formation volume factor of oil, formation volume factor of gas and liquid density, were performed for 158°F and 194°F temperatures. The measurements were conducted in two different apparatuses: an Hg system and an Hg-free PVT system. The results showed that the correct accounting of formation gas solubility in downhole conditions and during the kick circulation is a very important issue for safely drill deep and ultradeep water wells.
The study of gas solubility in drilling fluids started in the 1980s, when the focus of the studies was to understand the interaction between the drilling fluid and the formation fluid under reservoir pressure and temperatures . Depending on the thermodynamical conditions, that fluid interaction could modify drilling fluid properties complicating even more a kick situation, with the risk of hydrates formation inside the well or at the surface. Due to the drilling fluid and reservoir fluid interaction it could also be possible to occur reservoir deposition of solids (asphalthenes, paraffins or salts), causing serious formation damage.
O'Brien  discussed gas solubility in water based and oil based drilling fluids, considering well control aspects of the problem. According to the author, natural gas solubility in oil based fluids could be 10 to 100 times greater than solubility in water based fluids, making it very difficult to detect a kick in an oil based system.
Thomas et al.  measured saturation pressures for methane-diesel No. 2 and methane-diesel based drilling fluid, at 100 F. The authors concluded that methane solubility in pure Diesel oil was greater than in the oil based mud, due to the presence of brine, emulsifier and solids in the mud.
O'Bryan  expanded Thomas et al. work by investigating the saturation pressures of diesel, Conoco LVT and Mentor 28 oils with methane, at 100 F. In fact, the author performed a broad study of saturation pressures for methane-Mentor 28 a and methane-Mentor 28 based drilling fluid, at 100, 200 and 300 F. The author concluded that the solids do not play an important role in the solubility of methane in the oil based fluid and that 95% of methane solubility was in the oil phase, 4.5% in the emulsifier and 0.5% in the brine.
O'Bryan et al.  performed experimental solubility studies with other gases (methane, ethane, natural gas and CO2) in diesel oil. In terms of oil based fluids, the effect of solids content in the overall solubility of the mud was investigated and the form for the evaluation of overall solubility based on the volume fraction of oil, brine and emulsifier was devised.
O'Bryan et al.  estimated the formation volume factor of oil of the saturated oil based mud applying Peng and Robinson  correlation. The authors also developed an empirical correlation for the solubility of the mud in order to evaluate the saturation pressure os the gas-mud mixture.
Berthezene et al.  studied methane solubility in four liquids (Diesel, Mineral, Olefin and Ester oil), at a temperature of 194°F and a pressure range from 2175 through 5076 psi. The authors verified that the solubility in the fluid mixtures was proportional to the solubility in water and oil, respectively. The results could be extrapolated to other pressure and temperature conditions by thermodynamical modeling applying Peng and Robinson  equation of state.