Improved Drilling Performance and Cost Reduction Through Straight-Hole-Motor Drilling in the Fort Worth Basin
Authors: Johnston E.H. 
Published: December 2007

This paper is SPE 31160. Technology Today Series articles provide useful summary information on both classic and emerging concepts in petroleum engineering. Purpose: To provide the general reader with a basic understanding of a significant concept, technique, or development within a specific area of technology. Journal of Petroleum Technology, November 1995.

Summary
This paper discusses Mitchell Energy Corp.'s attempt to improve performance and to reduce drilling cost through routine drilling with downhole mud motors. The potential to increase rate of penetration (ROP) and to reduce drillstring attrition was the primary driver for developing a practical straight-hole-motor (SHM) operation. An economic criterion based on ROP increase compared with that in conventional rotary-drilled offset wells was established to monitor performance to justify motor expense. During the trial and learning phases, problems were encountered and the ROP-based economic criterion was barely met; however, additional benefits emerged. Hole enlargement was significantly reduced, which led to mud and cement savings, and less hole rugosity improved general log quality. These early results prompted the persistence needed for problem resolution. Thus, drilling contractor, operator, and service company personnel worked together as a team and developed a SHM operation beneficial to all.

Introduction
Mitchell Energy has extensive drilling experience in the Fort Worth basin (nearly 4,000 wells since 1952). Experience has shown that ROP significantly increases with increased rotary speed, and numerous wells were drilled with rotary speeds in the 100- to 150-rev/min range. Attempts to extend drillstring component life by identifying and avoiding critical rotary speeds were unsuccessful. Field experience suggested that some type of damaging motion occurred somewhere along the drillstring at virtually any rotary speed greater than 75 rev/min. Through trial and error, a bottomhole assembly (BHA) was developed that resisted fatigue damage, but rapid OD wear and drillpipe fatigue damage continued. Drillpipe was upgraded from 4 1/2-in., 16.60-lbm/ft Grade E to 4 1/2-in., 20-lbm/ft Grade E; however, fatigue failures recurred with only 220,000 ft of hole drilled (1 year). In 1991, 94 wells were drilled with an average of two drillstring failures per well and an average of 4 hours of downtime per failure. Even so, the higher operating costs were being defrayed by increased ROP. Uncertainties about drillpipe availability and cost, drilling rig wear and tear, and the risks of hole trouble and twist off made the need for an alternative to high rotary speed evident. Because the cost of slowing down (including drilling fewer wells) was unacceptable, the feasibility of a SHM application was evaluated.

Economic Criterion
To evaluate the feasibility of SHM drilling, an economic criterion was established whereby drilling performance could be monitored with respect to motor expense. The chosen criterion is a simple ROP comparison of motor-drilled wells to the nearest and most recent, conventionally drilled offset wells. Break even (at equivalent depth) occurs when
(1)
The hourly drilling cost, Cd, is the sum of all time-dependent costs. Some of these costs are determined directly (e.g., rig rate, rentals, and supervision). Other costs, such as fuel, mud, and water, accumulate with time and are estimated by historical method. Drillstring attrition and other rig considerations are omitted from the hourly drilling cost so that the evaluation can be extended to daywork drilling when company rigs are not used. When company rigs are used, the hourly drilling cost is calculated to be $295/hr.
The term for surface-hole rotating hours, ts, is present because motors are not used to drill surface holes. Surface holes can be drilled quickly without motors, and the larger size and use of retipped mill-tooth bits preclude their use. When company rigs are used, the average value ts is 4.2 rotating hours.
With $100/hr for motor cost, Cm, and substituting values for Cd and ts, Eq. 1 becomes
(2)
Because a great number of variables are involved in actual drilling situations (i.e., every hole is different), a well that apparently fails to meet the economic criterion does not necessarily constitute an economic failure. The results of multiple wells are required to average out these variations. Also, because wells drilled in the Fort Worth basin vary in total depth (TD), depending on objectives and proximity, multiple-well analysis requires a relationship between ROP and depth. This relationship is characterized by a growing decrease in ROP with depth, which, in terms of rotating hours vs. depth, is linearly approximated by
(3)
Eq. 3 allows the use of linear-regression analysis to generate average rotating hours vs. depth curves by use of wells with different TD's and/or use of multiple depth points from wells.
Fig. 1 plots the company's first 66 SHM-drilled wells and the corresponding conventionally drilled offset wells. With regression analysis to determine m and b in Eq. 3, three average rotating hours vs. depth curves were fitted to the data. The top curve fits the 66 conventionally drilled offset wells.
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