Optimized Drilling Through Use Of Downnhole Motors

Abstract

It has been established that rate of penetration (ROP) is directly related to rotational speed (RPM) of the drill bit in most formations. The Wembley area of northwest Alberta shows a proportionate increase in drilling rate with increases in rotary speed. Pan Canadian Petroleum Ltd. (PCP) optimized bit RPM by supplementing the rig's rotary capability with downhole motors. This paper will summarize the results of using downhole motors to Increase penetration rates in the Wembley field and will provide the drilling plan which PanCanadian uses to optimize vertical drilling with downhole motors. Introduction The relationship for soft and medium soft formations, between rate of penetration and rotational speed has been established as(1): (1) R = KWN a where: R = Rate of penetration K = Lithology factor N = Rotary speed W = Weight on bit a = exponent (equal to 1 for Wembley) For Wembley area this equation may be reduced to: (2) R = constant ( N ) Although the constant includes the bit weight, which is a variable, by drill off tests and manufacturer's recommendations bit weight has been optimized at a relatively constant value between 18 000 and 20 000 daN. Equation (2) suggests the rate of penetration can be enhanced through rotary speed increases. Factors which place an upper limit on rotary speed include:Drill string limitations.Drilling rig limitations on rotary speed.Drill bit limitations.Mechanical hole erosion.Casing wear. Drill string limitations include resonant vibration, joint strength, wear due to erosion and cyclic bending fatigue. Contractors limit rotary speed to 150 RPM or less and will not warrant the operational integrity of the string at higher rotary speeds. An excellent reference paper has been prepared by D. Dareing of Maurer Engineering Inc. (Ref. SPE 11228). Therefore most conventional drilling rigs are limited to rotary speeds of 150 RPM. Chain drive rotary tables are in common use and are usually coupled from the drawworks power take-off directly to the rotary drive pinion. Due to substructure space limitations it is not often possible to include a transmission on the rotary table. Chain sprockets also tend to be fixed by rotary torque requirements and chain speed limits. Torque tubes and electric drive rotaries have added flexibility to available RPM but these systems are not always available. Retrofit on existing rigs cannot be economically justified unless a long-term rig commitment is possible. Drill bit manufacturer's suggest RPM limits for their products but recent developments in premium sealed bearings have allowed greater flexibility. Also, insert bits have been improved in the bonding of carbide teeth to the cone matrix, allowing higher rotary speeds. Casing wear is a concern to all operators and, in some cases, optimum drilling performance has been sacrificed to limit wear. Non-rotating stabilizers have been used successfully but, again, stabilizer wear increases substantially when the drill string is rotated above 100 RPM.