No abstract

Bottom Hole Assembly (BHA) reliability is critical to deliver wells on-time and within budget. Improving reliability is a combined effort between operators and service providers. In the D.J. Basin, well drilling times are between 48-60hours. A 10-hour trip for failure can account for over 20% of well time. Onshore operations have benefited from focusing on performance metrics. To achieve some metrics, drilling procedures have been implemented that may have had unintended consequences. It will be shown how a review and change to standard drilling practices helped improve BHA reliability BHA failures occurred on 35% of wells in the operating area of this project. Although steps were taken, such as third-party inspections of tool builds, trialing various BHA components, and adjusting drilling parameters, failure still occurred. Failures were split between motors, measurement while drilling (MWD) and rotary steerable system (RSS) tools. Motor chunking was present on most BHAs, regardless of vendor. Chunking either caused motor failure or blocking of MWD or RSS components despite filters downstream of the motor. A review of operating practices with the service provider concluded that modifications could reduce on-bottom and off-bottom BHA loads and improve reliability. A series of procedural changes were made to connection practices, back-to-bottom procedures and downlink practices and the results tracked. Increased motor reliability was the main goal and would be determined by post-run observations of chunking evidence. A secondary aim was to reduce other failures that may be caused by mechanical overload. After implementing the procedural changes, the first 11 wells were completed in a single run, with no non-productive time (NPT) for BHA failures and no motor rubber observed in filter subs. Several wells were also able to re-run the RSS resulting in an invoice credit and further cost savings. Although the changes have resulted in a small increase in connection time per well, the pad level time savings from improved BHA reliability offsets that cost. There is also greater confidence that the applied drilling parameters start from a zero-load point. This allows the operator and service company to have more confidence that downhole tools are not being overloaded and gives more opportunity to optimize drilling parameters for performance. This paper will challenge standard practices that target incremental performance gains but may result in seemingly unrelated BHA reliability problems. Modeling drillstring stretch and understanding BHA load conditions has resulted in reliability improvements for the basin that can be applied to similar applications for the operator and the industry.

Vibration and drilling dysfunction continue to be a limiting factor to drilling performance. Minimizing vibration lowers the failure rate of downhole tools from short term catastrophic failures to longer term fatigue failures. Minimizing dysfunction reduces bit and BHA damage which reduces bit trips and improves performance as optimal operating parameters can be applied for longer. In onshore operations, short well cycle times strain logistics and asset availability. Rerunning assets, such as rotary steerable and MWD tools, is a significant cost saving to both the operator and service company. Mitigating vibration can be achieved through BHA design, bit design, and manipulating drilling parameters. However, these can be uneconomical, because they require a lot of trial and error, along with, multiple combinations and iterations. Using downhole vibration mitigation tools can be a more cost-effective method of reducing vibration while achieving economic drilling performance. This example from the D.J. Basin, Colorado, used two different downhole vibration mitigation tools to try and reduce the magnitude of vibration, specifically, tangential vibration, which posed a higher risk of failure to the directional drilling tools. Four wells on a single pad were selected for the trial to ensure similar geology and well design. Four wells that had comparable geological and well profiles, were selected as offsets. The aim was to reduce vibration and successfully rerun the directional drilling tool on at least two consecutive wells, while maintaining the offset well's ROP. The paper will outline the design of the two technologies and the results from each well. Changes in vibration magnitude will be explained and the effect on ROP. The paper will compare the four trial wells to the four offsets and contrast the performance of the two tools in the trial wells. The paper will also discuss mechanisms unaffected by the technology and how that provided insight into the interrelationship of vibration mechanisms. During the technology evaluation process, it became apparent that the run history with vibration mitigation tools was relatively low for the D.J. Basin. Of the two technologies, only one had previous experience in the basin with less than 50 runs over the previous 10 years. This was the first application of this type of downhole technology for this operator in this basin. The results have identified vibration as a performance founder point and helped demonstrate the change in performance that can be achieved by reducing drilling dysfunction.