Drilling automation

Collaborative Approach to Implementation Helps Realize Benefits of Drilling Automation

This paper describes a collaborative effort between an operator, a drilling contractor, and a service company to introduce specific aspects of automated technology to a major drilling operation.


The application of automated technologies to the process of well construction is emerging as key to improving the overall efficiency of drilling performance. Though not yet mainstream, several recent applications have demonstrated that technology maturity is no longer the limiting factor in accelerating implementation and realizing the benefits of automation. This paper describes a collaborative effort between an operator, a drilling contractor, and a service company to introduce specific aspects of automated technology to a major drilling operation.

Project Context and Technology Business Drivers

In 2012, the company began developing a giant gas greenfield that required nearly 300 wells to be drilled. Among the many challenges on a project of this magnitude was the need to drive well-construction costs down. An important aspect of well-construction cost is the time spent drilling, which is largely influenced by the slow rate of penetration (ROP) prevalent in the field because of the high rock strength. In order to deliver the performance enhancements required, the company set up an integrated hard-rock drilling team.

In addition to the objective of increasing ROP, several other aspects of the technology made it attractive. These include that

  • Automation presents a systematic approach to improve consistency of performance across multiple rigs and wells.
  • Automation can supplement the competency and capacity of drillers.

Automation Project Goals

In early 2014, the company agreed on a plan to bring this technology to the field in collaboration with the project’s major drilling contractor and drilling service provider (DSP), the supplier of the drilling automation technology.

Additionally, because the drilling rig was recognized as a major component of the technology delivery, the company engaged in focused discussions to build alignment with the main drilling contractor to ensure that the right resources were available throughout the project.

Finally, the DSP and the drilling contractor implemented a bilateral agreement that covered the scope of work and protected each party’s contribution to the project.

With all this in place, the project deliverables were defined as follows:

  • Complete three open-loop field trials of the DSP’s ROP-optimization software, and evaluate the opportunities and areas for improvement.
  • Design, build, and test an interface between the DSP’s automation system and the drilling contractor’s drilling control system.
  • Install the DSP’s drilling automation systems and interface with operator-designated drilling rigs.
  • Complete three closed-loop field trials of the DSP’s drilling automation systems, and evaluate the opportunities and areas for improvement.

Technology Description

Three main components of the technology were required to enable the automation of drilling-parameter controls:

  • A method to analyze the data in real time and determine the appropriate settings for weight on bit and revolutions per minute, referred to as the ROP-optimization system
  • A platform to house the optimization system and manage the data feed into and out of it, as well as support communication with the rig’s drilling control system, referred to as the drilling automation system (DAS)
  • A control gateway to the rig’s drilling control system that provides secure, bidirectional data communication enabling a third party to control and operate major rig equipment within a managed set of rules

The first two were provided by the DSP, while the latter was provided by the drilling contractor in conjunction with the control-system manufacturer.
DAS. The DAS is an intelligent decision-management system that is designed to deal with constantly changing drilling conditions. In specific scenarios, by integrating surface and downhole data, it is able to diagnose the situation and execute a series of preprogrammed, consistent, and standardized well-­construction operations.

The DAS is designed with two key objectives:

  • To support through its automation capability the consistent application of operational procedures and to consolidate the improvements, gains, and lessons learned
  • To improve through its optimization modules the overall drilling performance by improving key aspects of the well-construction process

ROP-Optimization System. Several upgrades of the system were incorporated into the software version used during the closed-loop trials. These include the ability to autonomously detect and determine the severity level of stick/slip and automatically implement a customized mitigation strategy.

Control Gateway. The rig contractor and the control-system manufacturer collaborated to provide a two-way data connection on the rig, which permits a third party to receive data and send commands to the rig equipment. The system requires the installation of a dedicated programmable-logic controller, a human/machine-interface display, automated speed throttles, and indicator lights.

Open-Loop Field Trials

In open-loop mode, computed set points are presented to the operator as recommendations. The operator can choose to implement or ignore these recommendations, depending on his judgment of operational circumstances. A series of open-loop trials was initiated in early 2014.

Open-Loop Trial 1. This trial highlighted several key lessons, the most important of which was to have a set of well-defined and widely-agreed-upon drilling-parameter limits. The trial was conducted without having these in place, and, while the optimization algorithm demonstrated the ability to deliver increased ROP over several formations, results indicate that the bit became damaged midway through the run, thus compromising ROP during the latter half of the interval. The run fell 224 m short of its target, and overall ROP performance was categorized as average when compared with that of offset wells.

Open-Loop Trial 2. On the basis of the lessons learned from the previous trial, a second trial was conducted. Much-improved performance was observed, with the bit exceeding its target interval length by 197 m, delivering the second-longest run in the field at the time.

Open-Loop Trial 3. A final open-loop trial saw some technical limitations. The issue of two sources of data (rig sensor and mud logging) and the inherent discrepancies between them could not be solved as planned, and the trial continued with the same data setup as the previous two trials.

Open-Loop Key Lessons. Several key lessons were captured from the series of open-loop trials, and these were then fed into the design and planning of the closed-loop trials. Some of the key lessons were

  • The ROP-optimization algorithm requires engineered parameter limits. Despite the observation on the first trial that, in some instances, unconstrained parameters can produce significantly higher ROP, in order to meet the goal of a single bit run for the 12.25-in. interval, operating-parameter limits by formation must be defined before drilling.
  • A single source of data is required for model and control. Discrepancies between mud-logging and rig-sensor data presented significant challenges during open-loop testing.
  • The driller is not always able to execute recommendations because of multitasking. While the feedback from the driller was that the algorithm generally provided credible recommendations, it was often a challenge for the driller to keep up with the recommendations because of other tasks he was conducting in parallel.
  • Generally, better ROPs were observed with higher compliance to the optimization algorithm’s recommendations.
  • The algorithm did not have any functionality to recommend changes to operating parameters as a result of encountering hard stringers.
  • The driller should have a systematic method for assessing the severity of stick/slip and hard stringers. On the third trial, the bottomhole assembly did not contain any shock and vibration sensors, so the driller was left to determine the onset of stick/slip on the basis of visual observation of the fluctuation of the needle on the torque gauge.

Closed-Loop Field Trials

In closed-loop mode, computed set points are executed through a system that allows these recommendations to be passed continuously to a control system without human interaction. The driller’s role is to supervise the process and cede control to the system or revoke it, depending on predetermined guidelines and driller judgment of operational circumstances.

Closed-loop trials began in mid-2016 and marked a major milestone for the company, the DSP, and the drilling contractor. The testing included a series of “cold” tests (no drillpipe in the hole) to establish connectivity and data flow; conduct system behavioral checks, including authority allocation (handover of control); and check all the fail safes. A series of “hot” tests (with drillpipe) was then conducted while drilling out cement. These included starting in advise mode (open loop) and switching to control mode (closed loop) for incrementally longer periods.

Closed-Loop Key Lessons. At the time of writing, the closed-loop trials were still in progress. Some early learnings include

  • An improved strategy for managing stick/slip is required. To date, the DAS has demonstrated the capability to detect and implement a defined mitigation sequence. However, some examples in the data show that, once the event is mitigated, the application goes back into optimization mode and very quickly re-establishes the stick/slip condition.
  • Improved fault indication for the driller is required. Currently, a few very generic messages that are associated with a fault in the system appear on the driller’s main console. Work is ongoing to refine these so that they are more helpful.


From a tactical standpoint, the focus of these initial closed-loop trials has been, in large part, about debugging the technology, clearly understanding where the performance and technical gaps in the system are, and getting the drillers and wellsite leaders comfortable with the system.

From a strategic perspective, it has been interesting to see how the positioning of automation has changed as the project has evolved. When initially conceived, automation was seen as an opportunity to deliver improved ROP. Three years later, the drilling performance has improved significantly as the drilling teams have moved along the learning curve.

This change in perspective of what automation brings is not limited to the ROP challenge but is a key element relevant to multiple well-construction tasks. This approach is a major element to support the adoption of a manufacturing-style approach to well construction, which is gaining momentum in the industry.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184695, “Development to Delivery—A Collaborative Approach to Implementing Drilling Automation,” by Riaz Israel, SPE, Julian Farthing, SPE, and Hamish Walker, BP; Rodrigo Gallo Covarrubias and Jason Bryant, Schlumberger; and Christian Vahle, KCA Deutag Drilling, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, 14–16 March. The paper has not been peer reviewed.