A Microbit Investigation of the Potential For Improving the Drilling Rate of Oil-Base Muds in Low-Permeability Rocks

Abstract

Laboratory tests using milled-tooth and diamond microbits compared drilling rates in water, water-base mud, oil-base mud, and specially formulated oil-base muds. The oil-base muds containing minimum colloidal material improved drilling rates with milled-tooth bits very little, but the improvement in drilling rates with diamond bits was substantial. Introduction Oil-base muds are disagreeable to use and expensive to prepare. Howeverfortunately for the drilling industrycertain things that cannot be accomplished with the current water-base systems can be carried out with oil-base muds. Most of the advantages of an oil-base mud become more important as wells are drilled deeper and deeper to find productive formations. Oil-base drilling fluids were first used to prevent damage to productive formations. These early oil-base fluids were simply viscous crude or refined oils. They were viscous in order to lift solids out of the hole and to limit the loss of the oil to the formation through seepage or filtration. Attempts were made to use calcium oxide to react with the water that inevitably became incorporated into the mud. Even at that early date, oil-base fluids had the reputation of slowing down the drilling. Later, oil-base muds were formulated with emulsifiers and surfactants to avoid water-wetting the solids. A moderate concentration of water could then be maintained for improved performance and lower cost. Oil-base muds (or invert emulsion's) did not achieve their current versatility, however, until oil-dispersible clays became available to prepare a low-viscosity mud having good suspension capabilities and filtration control at high temperature. This type of mud can give reasonable drilling rates in most situations, but in deep drilling the oil-base mud again slows drilling rates in low-permeability rock. Except for its effect on drilling rate, the oil-base mud is ideally suited for deep drilling. A good oil mud is more stable at high temperature than the best of the water-base systems. Salt sections and formations that contain water-reactive components can be drilled without difficulty. Hydrogen sulfide and carbon dioxide present neither a stability problem nor a corrosion problem when electrically problem nor a corrosion problem when electrically nonconductive oil-base mud is used. The water phase of the oil-base mud can be adjusted to prevent shale hydration and thus provide good hole conditions for the long periods required to dull a deep hole. All these advantages made it worthwhile to explore the possibility of improving the drilling rate of oil-base mud in rocks of low permeability. Background In 1958 Moore used laboratory drilling equipment to study the effect of apparent viscosity on drilling rate in Indiana limestone (approximately 10 md). He tested at a weight on bit of 1,000 lb, 60 rpm, 5 gal/min, and a differential pressure of 500 psi. He ran tests in a bentonite mud and in water to which glycerine had been added to increase its viscosity. He found that the viscosity created with either technique produced roughly the same effect on drilling rate. Following are some of his conclusions:A viscosity increase imparted to a liquid system by any means will tend to reduce drilling rate.There appear to be two logical reasons why viscosity slows down the rate of rock penetration: JPT P. 507