An Experimental Study of Gas Influx in Oil-Based Drilling Fluids for Improved Modeling of High-Pressure, High-Temperature Wells

Abstract

Summary Oilfield exploration in extreme areas represents additional requirements for drilling-fluid performance and hydraulic models for well control. In general, there is little knowledge about the drilling-fluid properties at high-pressure/high-temperature (HP/HT) conditions, and kick models are based on extrapolation of fluid properties from moderate pressures and temperatures. To verify the validity of extrapolation to downhole HP/HT conditions, increased knowledge about the drilling-fluid behavior under these conditions is required. In this work, we have experimentally determined the effect of gas absorption on saturation pressure, density, and viscosity at temperatures up to 200°C and at 1,000 bar. We provide accurate measurements of methane solubility in two oil-based drilling fluids (OBDFs), which both have the same composition except for the type of base oil (BO). One is based on a refined normal mineral oil, and the other is based on a linear paraffin. For various CH4/OBDF combinations, density and viscosity are measured at pressures and temperatures ranging from standard conditions to HP/HT. The two OBDFs reveal similar flow behavior, but the one that is based on a linear paraffin oil has a stronger gel structure and a stronger shear-thinning effect. This fluid enters the dense-phase region at a lower pressure, and is accordingly able to absorb more gas at a lower pressure than the fluid with a normal mineral oil. Results have been used to validate computational predictions. It is shown that the experimental results form an important basis for tuning the software model to fit the thermodynamic properties of gas-loaded drilling fluid at HP/HT conditions.