Severe torsional vibration is consistently unrecognized as a major problem in the US land tight-shale drilling sector and, therefore, has little documentation surrounding this issue. However, high-speed downhole dynamics sensors, placed in multiple locations along the drill string, have shown that the most extreme form of torsional vibration, stick-slip, actually plays a significant role inhibiting drilling performance in the Eagle Ford shale play, particularly when drilling deviated wells up to 18,000ft. Stick-slip generates excessive cyclic downhole rotational speed variations with high peaks that may induce extreme lateral shocks and accelerations, which reduces the life of downhole tools. Over the course of a 13 well drilling program, an upgrade to the top drive control software resulted in:• Dramatically reduced downhole rotational speed oscillations. Stick-slip effectively mitigated. • Consistently improved torque energy throughput from surface to downhole. • Improved directional control of downhole steering tools and performance of measurement while drilling (MWD).-Stick-slip generated noise on MWD telemetry tool, which made data packet difficult to decode at surface.• Estimated downhole speed validated by high-speed downhole sensors. Useful for improving drilling decisions.The following long-term goals were also pursued within this endeavor:• Increased wellbore quality.• Reduced mechanical tool failures. Increased downhole tool reliability.• Enhanced bit life and performance prevented premature bit wear.• Reduced number of trips to replace damaged bits and tools.• Increased top drive life.Integrating active-damping torsional vibration mitigation software into the rig control system creates exceptional value as an easy-to-implement alternative to a traditional downhole tool and virtually eliminating unnecessary trips out of hole to service or replace the tools. The advantage of this type of software technology is that it can function successfully in any rotary drilling environment, regardless of the hole size, bit design, bottom hole assembly (BHA) design, lithology or well trajectory. These observations have been validated by high-speed drilling dynamics data acquired from both surface and downhole that demonstrate the dramatic, positive changes in the drilling environment when this technology is activated. The data input required by this technology is surface drill pipe rotational speed, surface torque and drill string geometry. The only output of this technology is rpm modulation around the control system's set point.The impact of this active torsional vibration mitigation technology is global. It has the ability to have a positive impact in most drilling markets, in such applications as land, barge, jack-ups and even in deep water applications with semi-submersibles and drillships. The following core benefits of this technology immediately drive value into any market's bottom line: reduced destructive downhole vibration, increased downhole tool reliability, increased downhole tool control, reduced non-...

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.

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:1. Conventional motors 2. Rotary steerable tools 3. Downhole motorized rotary steerable tools. Methods, Procedures, Process:This paper discusses the test program implemented across a 6-well project 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: 1. A surface-located, active stick-slip mitigation device 2. A closed-loop high-speed downhole weight on bit controller 3. An automated closed-loop, high-speed downhole data driven autodriller, aimed at maximizing rate of penetration whist minimizing all modes of vibration. 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 37%, 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 wit...

Drilling automation depends on delivery of high-speed downhole dynamics data to control surface machinery. The two principal surface machine parameters controlled by high-speed downhole data are top drive rotary speed and the tripping speed of drawworks. The high-speed downhole dynamics data is delivered to surface via complex downhole dynamics electronics packages with sensors that measure vibration, loads, temperature, and pressure. As the bottomhole temperature rises above the functional thresholds of these downhole electronics packages, the life and performance of the downhole tools and sensors deteriorate, making it uneconomical to perform closed-loop control that depends on the highspeed data.A breakthrough in land rig mud cooling technology now allows for much lower, safer downhole temperature gradients for the safe use of the necessary downhole dynamics tools to fully automate the drilling process. The closed-loop mud cooler was used on a series of wells in South Texas with advanced drilling automation tools to compare the results of drilling speed, efficiency, and downhole tool operational safety with the mud cooler either activated or deactivated.During the tests, the frequency of downhole tool failures diminished from two temperature-related failures per well to zero tool failures, which in turn reduced the need for bit trips and expedited the overall drilling rate. The operator drilled the well in three days fewer than the previous well.The high-speed downhole dynamics measurement tool that controls the automated driller at surface usually has a maximum battery life of 250 hours. When the mud cooler was used, the downhole dynamics tool was able to achieve 96% of its capacity (240 out of 250 hours) for the first time in an environment where downhole temperatures exceeded 250°F. The previous maximum tool life achieved was only 167 hours (67% of the total battery capacity); meaning run length capability was increased by 44%. Even if downhole dynamics data is transmitted to the surface at a rate insufficient for automated surface machine control, the slower data will still allow the driller to make better performance drilling decisions. The mud cooler allows for a reduction in temperature of up to 45°F (at surface) and 21°F at bottom hole in a single pass for flow rates up to 550 gallons per minute during the summer time.This paper focuses on performance data and charts for the overall operations on multiple wells drilled as part of a drilling automation case study in a hot-hole application in South Texas (Eagle Ford Shale).

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 12¼", 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.