Proper Selection Of Drill Bits And Their Use
Authors: Hightower W.J. 
Published: December 2007

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This paper is to be presented at the Mechanical Engineering Aspects of Drilling Production Symposium in Fort Worth, Tex., on March 23–24, 1964, and is considered the property of Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of the Journal of Petroleum Engineers or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A procedure for drilling abruptly changing formation is discussed. This procedure includes the use of electrical and radioactivity well logs and five foot interval drilling times to arrive at operating conditions for the bit and to aid in bit selection.

The results of a number of field tests have shown a significant improvement in bit performance.

Introduction

On drilling rigs that do not have independent rotary drives, the normal operating practice used today is to select one of the rotary speeds available in the rig and to maintain that rotary speed daring the entire bit run. It is also a general practice for the driller to increase weight somewhat as the bit dulls in order to maintain an acceptable drilling rate. Normally, the bit is pulled when bearing failure or loss of gauge causes excess torque or unacceptable drilling rate indicates a dull bit. Practical experience and theoretical considerations for homogeneous formations have shown that moderate weight and high rotary speed are best for the fast drilling non-abrasive formations while heavier weight and lower rotary speed are better for the slow drilling abrasive formations. The low rotary speed is desirable in the abrasive formations because of extremely rapid tooth wear at high RPM. The high rotary speed is desirable in the non-abrasive formations because abrasive wear is not serious and in such formations drilling rate responds well to an increase in RPM.

These practices would be reasonably satisfactory if the formation abrasiveness and drillability remained constant throughout the bit run. It is known, however, that formations often change several times during a bit run and as a result the weight and rotary speed practices that are used on each bit are a compromise between the best weight and rotary speed for the individual formations drilled. Ideally, the best operating practices should be used for each different formation encountered.

The purpose of this paper is to discuss and show how well logs and drilling rate logs may be used in abruptly changing formations to determine what kind of formation is being drilled. Then by using practical experience and the theoretical work for homogeneous formations as a background, operating practices for each type of formation encountered may be selected. Performance comparisons are given showing the type of improvements that may be expected by using the procedures which are discussed in this paper.