The Role of Auto Driller, Rig Control Systems and Driller Procedures in Reduction of BHA Failures

Abstract

Abstract Reducing bottom hole assembly (BHA) failures has been the focus of this operator in US land intermediate and lateral sections to reduce cost per foot. BHA failures can be mitigated with better auto driller processes, improved rig control system technology and drilling mechanics based procedures. The operator, rig contractor and BHA service providers engaged in an intensive continuous improvement process for 18 months to help two rigs in Oklahoma reduce BHA's per well. The goal was to determine how to best tune the auto driller and standardize set point practices. By investigating this for each stand drilled, the plan was to improve bit run footage and reduce BHA tool failures per hole section. The rig contractor deployed a system upgrade and adjusted driller procedures to help identify auto driller dysfunction quicker. In-bit sensors that measured drilling parameters, vibration and strain were run to validate suspected downhole dysfunction and premature bit failure. The operator's procedure to quickly evaluate and mitigate auto driller dysfunction was trialed to distinguish rig control system induced dysfunction from downhole drilling mechanics dysfunction. For the Oklahoma rigs, auto driller stability was evaluated and improved in ∼50 BHA runs in the 12-1/4″ intermediate hole sections and in ∼100 BHA runs in the 8-3/4″ lateral BHA runs. Motor failures in the 12-1/4″ intermediate section and in the 8-3/4″ lateral sections were reduced, as were premature bit failures. Also, it was found that tool joint hang-up in the rotating head were exciting the rig control system into dysfunction and causing a significant reduction in downhole weight on bit (WOB), differential pressure (DP) and rate of penetration (ROP). These hang-up events were occurring 3 times per stand, and although ROP would recover after the tool joint exited the rotating head, damaging vibrations at the bit continued long after the ROP recovered. The operator's tool joint compensation procedure was implemented in subsequent runs and lateral bit vibration and dull condition improved substantially. The learnings from the auto driller continuous improvement process were cascaded to two additional rigs in another basin in East Texas. Reducing depth of cut (DOC) variance through ROP set point management in interbedded formations reduced required bit runs in the second basin as well. The rig contractor deployed an upgraded auto driller system to minimize parameter variance and extend the life motors in high temperature laterals reducing the risk of catastrophic failure. And the rig contractor and operator continue to develop and trial auto driller dysfunction alarms to alert to possible BHA dysfunction. New tools, processes and scorecards are being developed to aid in the identification of dysfunction in rotary and slide drilling.