The problem of obtaining a Maximum Economic Rate of drilling is the main task of engineers, tool pushers, superintendents, field drilling foremen and people involved in drilling research problems. A rig drilling at its Maximum Economic Rate will always make hole at a rate less than the maximum rate of penetration. However, in cases of extremely high rates of penetration, the conditions which give the Maximum Economic Rate will be very close to the conditions which give the maximum rate of penetration. In comparing the economic rate against the rate of penetration, the purpose for drilling the borehole must be considered. In drilling at the Maximum Economic Rate, geologic information of all types having practical interest to the oil company must be accumulated. The path which the drill takes in achieving its maximum depth should fall reasonably within the prerequisites set up by the operating company. The borehole itself should be free of any characteristics which might prevent the running and cementing of casing, of a suitable diameter, to the maximum depth drilled.
To drill this acceptable borehole, the drilling operating costs may be split into three general categories. First would be the "non-recurring costs" such as rig moving, road building, surface and protection casing, cementing of casing strings, primary wellhead equipment, and final logging of the borehole at total depth. The second group, "recurring costs", will include personnel salaries, rig insurance, depreciation of drilling equipment, supplies, drilling mud, consulting fees, bit costs, rig lubricants, rig repair, rig fuel, and transportation charges. The third group is a "special costs" and is an addition to the recurring and non-recurring charges. This would include loss of circulation, blow-out, fishing and sidetracking operations, and problems of borehole deviation control. Because of the recurring costs and exposure time to the "special costs", it is important that the rate of penetration be as high as is practical.
In the early days of rotary drilling, a bit was screwed onto the bottom of the drill pipe and run in the borehole. The hole was drilled by rotating the bit under the compressive loading of the drill pipe. This type of drilling resulted in the questionable acceptability of the hole for running casing and in extremely high maintenance cost of the drill pipe. Special costs, resulting from fishing operations on drill pipe and casing stuck off bottom, multiplied rapidly as drilling depths increased.
Soon it was recognized that the amount of compression which could be transmitted through the drill pipe to the bit and thereby used to load the cones or the blades, was not directly proportional to the amount of weight which could be fed off the weight indicator. This is reasonable to assume when considering the limberness of the drill string, and the amount of torque which it was transmitting. The combination of compression and torque resulted in the helical buckling of the drill pipe above the bit. It was observed that the increased indicated drill pipe weight used in loading the bit could result in a substantial increase in rotary torque and a reduction in the penetration rate.
As the number of drill pipe joints in compression is increased, the amount of helical buckling increases. When the bending of the pipe against the side of the borehole exceeds 180 degrees of arc, Fig. 1., additional loading by compression will result in lateral forces being applied against the drill pipe by the wall of the borehole. These are frictional forces which increase drill pipe torque and decrease the effective weight which may be transmitted to-the drill bit. Fig. 2-A illustrates drill pipe run in compression. If the wall of the borehole does not have a constant radius similar to that of a cylinder through the area where the drill pipe is run in compression,, then much of the indicated surface drilling weight may be lost by wall support of the drill string. Under these conditions, increases in indicated bit weight will result in a decrease in effective bit weight.