Laboratory Drilling Rate and Filtration Studies of Clay And Polymer Drilling Fluids

ABSTRACT Recent efforts to design drilling fluids for increased drilling rates have confirmed some laboratory results of other investigators, but have also produced additional data that should be considered. These data were obtained under controlled test conditions using a microbit drilling machine. Clays and some polymers have previously been reported to cause reduction in drilling rate. Recent data have shown that under laboratory conditions, suspensions of a single clay or polymer have sometimes given faster drilling rates than when water was used. Measurements have been made of clay suspensions and polymer suspensions comparing filtration - under API conditions, - while drilling with temperature of 150F and differential pressure of 1,000 psi and - under dynamic conditions after drilling. Some correlation between instantaneous filtration (while drilling) and drilling rate has been observed. INTRODUCTION Several papers have been presented that related drilling fluids to penetration rate. Generally, it was found that a decrease in the solids concentration resulted in significant increases in the drilling rate. Of course, this change also resulted in a decrease in the viscosity of the drilling fluid. Conclusions from investigations by this laboratory are in agreement. Data have shown that of the simple mud measurements commonly made at the drilling rig (density, plastic viscosity, yield point, API filtrate and total solids), only the density and total solids have a significant relationship to the drilling rate in Berea sandstone when attempting to correlate a single mud property individually. More recent drilling rate experiments have been designed to study - effects of individual clays and polymers on drilling rates in Berea sandstone and Lueders limestone, - the relationship between drilling rate and dynamic filtration as measured after drilling and - the relationship between drilling rate and dynamic filtration as measured during drilling. Data show that drilling rates are dependent upon type and concentration of particles, type of formation and filtration of the individual fluids while drilling. DEFINITIONS Mud pressure: pressure of drilling fluid as measured after leaving the drilling chamber (Fig. 1). This is taken to be approximately the mud pressure just past the bit and at the face of the formation. Terrastatic pressure: pressure representing weight of overburden. Formation pressure: pressure of formation fluid as measured at outlet of drilling chamber (Fig. 1). This is taken to be approximately the pressure of fluid in the interstices of the formation. Differential pressure: difference between the mud pressure and formation pressure. LABORATORY EQUIPMENT AND TESTING PROCEDURE The drilling equipment was described in two previous publications. Main components are a drilling chamber, filter-heater, rotary drive and variable-speed circulating pump. Auxiliary pumps supply pressure boosts for the mud, terrastatic and formation pressures. All equipment is designed for 15,000 psi and 500F. Capacity of the circulating system is approximately 7 gal. The mechanical design was facilitated by moving the rock down onto the bit. Data collected with this design should not differ from that obtained by a normal design where the bit moves into the rock. Drilling fluid is pumped through 50 ft of 5/16-in ID pipe coiled in an oil bath, enters the rotary shaft at a right angle and is pumped through the jets on the bit (Fig. 1). Most of the drilled solids are extracted by a screen mounted in the circulating system on the suction side of the pump. Data reported in this paper were obtained by controlling these parameters: mud pressure, 5,000 psi; formation pressure, 4,000 psi; terrastatic pressure, 5,000 psi; force on bit, 1,000 lb; formation, Berea sandstone and Lueders limestone; flow rate, 7 gal/min; bit, 1 1/4-in. diameter with two 0.078-in jets; mud temperature, 150F; and rotary speed, 60 rpm. Mud pressure was controlled at 5,000 psi, thus giving a differential pressure of 1,000 psi even though the fluid densities varied. Cores of 3 9/16-in. diameter and 8 in. long were selected from quarry blocks to provide some control of grain size distribution, permeability and porosity. A 2-in. section was cut off each core and a 1-in. diameter plug was taken from this section.