Cuttings-beds formation while drilling wellbores is a common challenge, especially for horizontal wells, as drilled particles have higher area to be deposited and form cuttings-beds, which can cause several problems such as, increased torque and drag, pipe sticking or pipe breakage, among others. Removal of the drilled-cuttings is done by circulating a suitable drilling fluid through the wellbore. This paper presents results from laboratory tests with deposited cuttings-bed and the flow of a fluid to erode the bed. The simulated cuttings-bed is a 1m long deposited sand-bed in a horizontal section. Three different types of fluids are being used in the tests. To investigate how the rheological properties can affect the erodibility of the cuttings-bed, water (as a Newtonian fluid), a xanthan gum solution and a water-based drilling fluid prepared for an offshore field operation (as a non-Newtonian fluids) are applied. Ultrasound measurements together with differential bed weight have been used to analyze the fluid-bed interaction. Results have shown that the cuttings-bed is eroded by dune movement. Saltation and dragging of sand particles due to the fluid flow appear to create a crest and then avalanche them down. The different types of fluids undergo different shear rates from the same pump power as the viscosity changes, as well as flow rates dependency along the dune extent.

The occurrence of barite sag in drilling fluids has relatively often been the cause for gas kicks in oilwell drilling. The subsequent absorption of gas into drilling fluid could lower the density and reduce the viscosity of the drilling fluid, thereby aggravating both pressure control and hole cleaning. In this paper, we present experimental measurements of rheological properties and barite sag in a typical North Sea oil-based drilling fluid at downhole pressure and temperature conditions. A new experimental apparatus was setup for barite sag measurements at static condition with operational temperature and pressure capabilities up to 200 °C (392°F) and 1000 bar (14,503.8 psi), respectively. Rheometry measurements were conducted on fluid samples with and without barite particles at operating conditions up to 90 °C and 100 bar. We observed that at a typical shear rate of 250 s−1, which is experienced in 8.5″ hole annulus, the viscosity of fluid sample with barite increased nearly three times as that of the fluid sample without barite as the temperature and pressure increased. However, temperature effect on viscosity dominates at high shear rates compared to pressure effect. Furthermore, the fluid samples showed more shear-thinning effect with increasing yield stress as the temperature increased. On the other hand, barite sag measurements revealed that whereas fluid samples under high pressure are less prone to sag, high temperature fluid samples, however, promote sag significantly. The data from this study are useful to validate extrapolations used in computational models and to improve understanding and operational safety of sag phenomena at downhole conditions. We also discuss the importance of this study in optimizing drilling operations.