Effect of Bentonitic Fluid Properties On Drilling Rate

Abstract

Laboratory studies were conducted on kinematic viscosity, filtration rate, pressure gradient and permeability reduction beneath the bit, and the pressure gradient and permeability reduction beneath the bit, and the effects of solids concentration and of the formation's sensitivity to water. A major conclusion is that simply knowing one physical property of a fluid does not adequately account for the effect of that fluid on drilling rate. Introduction The question of which drilling fluid property controls drilling rate has often been asked, and conclusions have been derived from field and laboratory data. However, the conclusions are not all in agreement Young and Gray established a relationship between drilling rate and pressure gradient beneath the bit. They found that pressure gradients varied with the type of formation, the orientation of the bedding plane, the type of mud, and the difference between plane, the type of mud, and the difference between the mud-column pressure and the pressure within the core. Pressure gradients were greater in high-permeability rocks than in low-permeability rocks and were found to increase as the API fluid loss of the mud decreased. Several articles have been written concerning the effect of filtration rate on drilling rate. Eckel indicated that a viscosity relationship must also be considered in correlating drilling rate and filtration rate. Battelle Memorial Institute reported that low-fluid-loss muds decrease drilling rate because of the high viscosity of the muds and not because of fluid-loss properties. Homer et al. used microbit experiments properties. Homer et al. used microbit experiments to study filtration during drilling. No reliable correlation was established between dynamic filtration and rheological properties or API fluid loss. Cunningham and Goins have reported that drilling rates in shales were reduced as API fluid loss was reduced with the use of starch. The reduction in drilling rate appeared to be caused by the starch and not by the fluid-loss property. Young reported that in his microbit tests a property. Young reported that in his microbit tests a lowered API fluid loss reduced penetration rate in all rocks that were used at all borehole pressures and that these reductions were a result of higher pressure gradients for the low-fluid-loss mud. It is interesting to note that starch and lignosulfonate were used only in the low-fluid-loss mud. Myers and Gray reported that during bit-tooth impact tests, the lowering of API fluid loss from that of salt water to 3 cc for a mud significantly reduced the crater volume, and that if these laboratory results can be equated to results of field drilling, a similar reduction of drilling rate would be expected from lowering the fluid loss of the mud. Eckel reported that drilling rate in a given system with constant circulating rate and nozzle velocity is a function of the kinematic viscosity of the drilling fluid measured at near bit-nozzle shear rates, and that for the same kinematic viscosity, drilling rate is independent of solids content. Data available on the effect of solids on penetration rate are for weighted drilling fluids. Generally, an increase in density or solids in weighted systems results in a decrease in drilling rate. Lawhon et al. show that for best drilling rate results, type as well as concentration of clays or polymers should be considered. Their data also show that under certain laboratory conditions some types of clays or polymers can give drilling rates greater than those obtained with water. JPT P. 657