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Collaborating Authors
Coit, Andrew
Abstract This paper presents a case history of drilling automation system pilot deployment, inclusive of wired drill pipe on an Arctic drilling operation. This builds on the body of work that BP (the operator) previously presented in 2017 related to the deployment of an alternate drilling automation system. The focus will be on the challenges and lessons learned during this deployment over a series of development wells. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig's drilling control system. This platform hosts applications that interpret the activity on the rig and issue control setpoints to drive the operation of the rig's top drive, mud pumps, auto driller, drawworks, and slips. The second component introduced was a wired drill string, which provides access to high speed delivery of downhole data from a series of distributed downhole sensors, providing an opportunity to improve both automated control and real-time interpretation of downhole phenomena. The project team identified several key performance indicators both at the project level and for each well. The project level key performance indicators (KPIs) were designed to give the operator an understanding of the reliability and robustness of the hardware and software components of the automation system. The KPIs for the well were designed to assess the impact of the technology on drilling efficiency through aspects of invisible lost time reduction (connection and survey times). The well level KPIs also fed into the project KPIs by capturing uptime, reliability, and repeatability of the hardware and software components of the system. The paper describes several specific examples of where the benefits of the technology were realized as related to the KPIs above and describes some of the technical challenges encountered and fixes employed during the pilot campaign. The paper also gives an insight into some of the non-technical challenges related to deployment of this system, around human behavioral characteristics. It discusses how focused collaboration and communication from all the stakeholders was managed and directed towards a successful deployment. The work delivered on this project incorporates several technological innovations that were deployed for the first time on an active drilling operation. Delivery of these were important milestones for both the operator and the automation technology provider as part of their collaboration to increase the capability and reliability of these systems. The operator believes that this effort is key to allowing its drilling operations to realize longer term and sustainable benefits from automation.
- North America > United States > Texas (0.46)
- North America > United States > Alaska (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)
- Information Technology > Software (1.00)
- Information Technology > Architecture > Real Time Systems (0.67)
Abstract Objectives/Scope Today, during the development of unconventionals, lack of knowledge about the downhole dynamics environment creates a culture of conservatism where excessive safety margins need to be applied to prevent damage to the rig equipment, drill bits, drill string and sensitive drilling tools. By using a combination of high-speed downhole data, surface applications, and an automated control system, this risk can be reduced, drilling performance improved and non-productive time reduced. Unconventional wells are typically drilled with several different types of drive systems, so on this project the impact of the automated drilling system was methodically tested in combination with the following BHA drive types: Conventional motors Rotary steerable tools Downhole motorized rotary steerable tools. Methods, Procedures, Process This paper discusses the test program implemented across a drilling in the Eagle Ford unconventional shale formation in South Texas. It was essential at the pre-planning phase that key performance indicators were identified and a solid test plan was designed. A road map was put in place to fully analyze the performance benefits where the automated drilling applications were tested against drive system, formation type and wellbore geometry. The primary objectives were to identify which applications combined with which drive system delivered the largest, consistent performance gains and the greatest cost savings. The paper includes a detailed description of the various automated applications tested: A surface-located, active stick-slip mitigation device A closed-loop high-speed downhole weight on bit controller Results, Observations, Conclusions These technologies bring significant benefits to our industry, especially in the development of unconventional assets where it is becoming increasingly difficult to deliver step changes in performance with current crews and technology. The high-speed downhole-driven control of the rig equipment allowed the driller and the customer representatives to maximize the performance of the rig without compromising safety or the reliability of the equipment. Drilling with automated motor BHAs and automated non-motorized rotary steerable BHAs allowed for repeated improvements in drilling performance of , well on well. The fact that this performance increase is repeatable offers significant bottom line value for operators, by allowing reliable well delivery, forecasting and overall reduced well cost. Novel/Additive Information Downhole-automated drilling control described within this case study is a powerful tool to be used by existing drillers and directional drillers. The drilling crew must use the automated control system in partnership with specialized automated drilling applications to realize higher performance, without sacrificing safety margins or tool life. Even with an automated drilling system, optimum performance is measurably more difficult to achieve without optimal BHA design and drive type.
Field Tests Quantify Processes Utilizing an Enhanced Downhole Dynamics Measurement Tool for Vibration Mitigation and Performance Optimization
Veeningen, Daan (National Oilwell Varco) | Hewlett, Richard (National Oilwell Varco) | Salazar, Joe (National Oilwell Varco) | Coit, Andrew (National Oilwell Varco) | Furniss, Eric (National Oilwell Varco)
Abstract Today's drilling optimization process depends greatly upon post-well analysis of recorded downhole drilling dynamics. Sophisticated downhole sensors are limited by wireless telemetry systems that offer a relatively limited bandwidth with considerable latency. Real-time knowledge of subsurface conditions could improve drilling processes and allow the automated, closed-loop control of surface parameters based on high-frequency downhole data. This paper describes the development and field deployment of a new, high-frequency downhole measurement tool. This tool transmits multi-sensor data in real time through a wired drillstring telemetry system, virtually eliminating latency. This enhanced dynamics tool, which acquires downhole measurements at 800Hz, includes tri-axial vibration, RPM, downhole weight on bit, and downhole torque, as well as annular pressure and temperature. This data is instantaneously streamed to the surface and available at 80Hz for processing by surface acquisition systems. An advanced auto-driller controls the applied surface weight on bit based on the downhole dynamic measurements. Essentially, high-frequency downhole parameters become independent setpoints, supplementing information to the once-independent surface setpoints. This paper provides details regarding a two-month field test of 6¾" dynamics tools in six wells to quantify the operational impact of the new technologies and operating processes covering vertical and directional 12½", 8¾" and 8½" hole sections. Comparison is offered for drilling both with air and with fluids, as well as drilling with positive displacement motors and with rotary steerable systems. The field test included establishing a benchmark in the first well, followed by utilizing multi-axis vibration measurements over the course of the subsequent five wells to actively mitigate the shocks and vibrations. Operational performance was further optimized in the subsequent runs incorporating automated control of downhole weight.
- North America > United States > West Virginia (0.28)
- North America > United States > Pennsylvania (0.28)
- North America > United States > Ohio (0.28)
- (2 more...)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)