Oil field exploration in extreme areas represents additional requirements to 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 (HPHT) conditions, and kick models are based on extrapolation of fluid properties from moderate pressures and temperatures. In order to verify the validity of extrapolation to downhole HPHT conditions, increased knowledge about the rheology of drilling fluids 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 1000 bar. Results have been used to validate computational predictions.
We have developed an experimental setup for studying the effects of natural gas dissolved in petroleum fluids under conditions appropriate for drilling operations. The equipment comprises a sample cylinder in which drilling fluid and gas initially can be mixed at exact mass fractions, and the saturation pressure can be determined at the desired temperature. The gas loaded drilling fluid is transferred to a rheometer with a 1000 bar pressure cell and to a high pressure densitometer for viscosity and density measurements, respectively. Density predictions based on well-known models using commercial software have been compared with the experimentally determined fluid densities.
In this study we provide accurate measurements of methane solubility in two oil-based drilling fluids (OBDF), which both have the same composition except for the type of base oil. 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 HPHT. The two OBDFs reveal similar flow behaviour, but the one based on a linear paraffin oil has a stronger gel structure and a stronger shear-thinning effect. This fluid is also able to absorb more gas at lower pressure than the fluid with a normal mineral oil. It is shown that the experimental results form an important basis for tuning the software model to fit thermodynamic properties of gas loaded drilling fluid at HPHT conditions.
Well operation safety is the main concern at any oil field. Efficient and safe well operations depend on proper knowledge about the behaviour of gas influx in petroleum fluids and the impact of relevant temperature and pressure changes in the well. A major weakness in current models of kick detection is the lack of experimentally verified data for fluid properties at HPHT conditions. Drilling fluids are commonly analysed according to international standards, describing atmospheric conditions and only a few selected temperatures. The data from this study will be analysed and used to validate extrapolations used in computational models. Improved understanding of the two phase gas-drilling fluid flow in the well allows better prediction of gas absorption and improved operational safety.