In-situ heavy oil density and viscosity can vary laterally and vertically in carbonate reservoirs. The spatial distribution of these PVT properties must be determined accurately for reserve assessment, reservoir simulation, well placement and other field development processes.

Although laboratory PVT analysis is the industry-standard source for fluid properties, the extensive time required to restore and process heavy oil fluid samples often minimizes the impact of such information during the drilling phase. The use of wireline formation testers, capable of measuring in-situ density and viscosity, can greatly aid the decision-making process providing timely basic PVT data, in addition to guiding the fluid sampling program and increasing the quality of the samples to be taken.

While in-situ measurement of fluid density and viscosity in oil-based-mud is well-established, accurate determination of such properties can be quite challenging in water-based-mud environments; especially in those cases of water-dominated flow, strongly emulsified fluids or high fraction of sediments in the flow line. Several techniques, such as sampling point optimization, pressure and flow rate control during pump-out, and tool-string configuration can minimize the adverse effects, thereby improving measurement and sampling quality. Yet, there can still be cases where the measurement accuracy can be limited due to the specific combination of fluid and formation properties, and borehole conditions.

In this paper, several case histories in a variety of borehole and mud conditions, including highly deviated and ultra-reach extended horizontal wells, are presented with comparisons to laboratory data when available. Results indicate that accurate in-situ density and viscosity determination is possible when sufficient amount of oil is present in the flow line. Experience also shows that measurement quality can be affected in suboptimal conditions involving strong emulsions, or range of viscosities outside the sensor specifications.