Drilling automation

Wired Drillpipe, Closed-Loop Automation Technology Drive Performance Improvement

To accelerate learning, an operator deployed a real-time, closed-loop downhole automation system (DHAS) in conjunction with wired drillpipe in the 8¾-in.-hole section.

Drilling rig working in the Bakken
Photo courtesy of Hess

To accelerate learning, an operator deployed a real-time, closed-loop downhole automation system (DHAS) in conjunction with wired drillpipe in the 8¾-in.-hole section. The operator also used downhole memory tools in the 5⅞-in. lateral section to collect downhole drilling parameters and vibration data. The optimization process drew upon key elements from lean manufacturing concepts. It followed a “plan, do, check, adjust” (PDCA) loop, with the DHAS and the data provided by it affecting three concurrently moving performance-improvement cycles.


The operator selected the DHAS with 5-in. wired drillpipe because it was believed the real-time, high-speed data feed would accelerate the learning process. By making the downhole drilling environment visible in real time, the driller could apply this new understanding of the drilling environment to the automation system, to optimize drilling performance. It was also envisioned that the large amount of data available from the system would feed the PDCA cycle and result in lessons learned and performance improvements that could be implemented across the fleet. The idea was to instrument one rig and use the lessons learned to improve the performance of the entire fleet. The primary project goal was reducing cycle time while achieving a breakeven cost for the additional technology.

At the time, there was significant variability in cycle time as well as a significant difference between the best- and worst-performing rigs. To assess the rate of improvement and, thereby, the potential of the DHAS to improve drilling performance, the operator selected a lower-performance rig for the pilot test.

Drilling-Automation System

The DHAS maintains full control of the downhole drilling environment by using high-speed data transmitted through the wired drillpipe to the algorithm controlling the rig systems. The DHAS is illustrated in Fig. 1. In normal drilling conditions, the driller makes decisions on the basis of drilling knowledge to surpass drilling performances. The time re­action from the human interface is critical to control the drilling environment, especially for drilling-vibration mitigation. The DHAS interacts with the drawworks autodriller control system to take full control when engaged by the driller. The system can also be used during slide operations for directional drilling.

Fig. 1: DHAS schematic.


The system uses wired drillpipe to stream data from dynamic measurement tools to surface at high speed. These data can then be seen and used to make decisions on the surface, at a rate of 0.4 Hz. The data are viewable by personnel at the rigsite as well as remotely in the office. Measurements from the tool streamed to surface include

  • Downhole weight on bit (WOB)
  • Downhole torque
  • Rev/min
  • Gyro
  • Lateral vibration
  • Axial vibration
  • Annular pressure

Along with high-speed data visualization streaming to surface at 0.4 Hz, select channels are sent to the surface at 80 Hz to allow for closed-loop control of the auto­driller. The system allows the user to enter a desired downhole WOB measurement and then send commands to the auto­driller to reach that measurement. This is accomplished by sending surface WOB commands to the autodriller and monitoring the resulting downhole WOB coming from the dynamic measurement tool.
The DHAS was used in combination with other proven systems, such as a stick/slip-mitigation system, to help stabilize control of the drilling process.

Drilling-Improvement Process

Lean manufacturing processes implemented by energy companies continue to improve well-construction delivery and the resulting production. Well-­construction teams use the basic PDCA improvement process to create and protect value by finding and addressing value limiters that are blocking a better result. The continuous improvement cycle consists of the following four key steps:

  • Plan—Design the system to improve its function. Develop an implementation plan.
  • Do—Implement the plan. Recognize and address problems with corrective action.
  • Check—Analyze and recap results. Capture lessons and drive improvement.
  • Adjust—Identify and remove a limiter. Find and address value barriers.

Value limiters are processes, materials, tools, or practices restricting the value of a well. There is always a controlling limiter determining value. Limiters are usually a part of the planned operations. The concept of a value limiter helps identify the system constraints controlling the delivery of a standard work process. Rate-of-penetration (ROP) limiters are one type of value limiter and the focus of the drilling-automation pilot project. In the automation project, there were three key PDCA improvement cycles:

  • Real-time cycle—This cycle improves the performance of the system in the ground. This cycle primarily involved the wellsite team, with some input from the office support team.
  • Run-to-run cycle—This cycle selects the best system to put in the ground from the options available. This cycle involved both the wellsite team and the office support team.
  • Well-to-well cycle—This cycle addresses the root causes of ROP limiters and redesigns the system and gets its components to the wellsite. This cycle involved the office support team primarily, with input from the wellsite team.

Simultaneously managing these cycles and analyzing large amounts of data proved to be a significant limiter in itself. The wellsite experimentation and learning proceeded the fastest, and the analysis-based learning proved time consuming. Observation and analysis did not always agree, which resulted in more analysis to evaluate and assess the drilling system. The different visual data feeds and ways to consume downhole information also resulted in different viewpoints between wellsite and analysis teams. The resulting information and learning was fed into and out of each of the loops, as possible, at end-of-run after-action reviews. Predrill meetings combined as much relevant information from the three cycles as possible, to produce actionable results for wellsite operations.

Project Summary

The rig on which the project was conducted had not delivered a well in the top quartile of the fleet in more than 2 years. During the course of the four pads (A, B, C, and D) being drilled during the project, the vertical and curve sections of the well were drilled in the top 18% of fleet, on average. Comparing 2014 and 2015 performance, this rig improved 24% in terms of footage per day in the vertical interval compared with the rig fleet, which improved 17% over the same period. The project rig was second best compared with the individual year-on-year improvement of the other rigs.

To quantify the financial success of the project, the operator calculated a breakeven point by comparing the well times to the average well times. The footage for all well times was normalized. The target overall time for the 8¾-in. interval decreased by 20% because the benchmark changed from Pads A and B to Pads C and D.

On the four pads with 16 wells, six target intervals achieved breakeven costs and six missed breakeven by less than USD 100,000. The remaining four wells missed breakeven because of trouble time in the curve and the additional drilling time incurred experimenting with vertical bottomhole assemblies in tangents over 4°. This caused the overall project to miss breaking even. However, the lessons learned for the rig fleet easily justify the project cost.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178870, “Using Wired Drillpipe, High-Speed Downhole Data, and Closed-Loop Drilling-Automation Technology To Drive Performance Improvement Across Multiple Wells in the Bakken,” by Donald K. Trichel, SPE, and Matthew Isbell, SPE, Hess; Bruce Brown, BD Drilling Consultants; and Major Flash, SPE, Michael McRay, James Nieto, SPE, and Isaac Fonseca, National Oilwell Varco, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.