Automation may be the key to next-generation, difficult-to-exploit wells

By Jon Ruszka, Baker Hughes INTEQ

Today, operators faced with discovering and developing hydrocarbon reserves are facing more, and more extreme, challenges. Every year, reservoirs are becoming more challenging to find and exploit. Similarly, the environments in which these reservoirs are located are getting increasingly hostile – either because they are in remote areas or because they are positioned deeper below the Earth’s surface.

In addition, the need to improve field recovery will intensify and the efficiency of drilling operations in relation to BOE produced will continue to be a measure of field operators’ success, irrespective of field size. As conventional plays deplete, we will exploit different reservoir types. Finally, there are the personnel challenges. Personnel safety will remain the priority in drilling operations, and the industry must ensure there are enough competent personnel to make it all happen.

Many believe that part of the solution to these challenges lies in increased automation of drilling operations. This article examines one service company’s experience in developing and delivering automation to the directional drilling process.


In early 1988, the German government was committed to drilling an ultra-deep, vertical, scientific well, onshore in the Bavarian Oberpfalz region. This was called the Kontinentale Tiefbohrung der Bundesrepublik Deutschland — otherwise known as the Continental Deep Drilling, or “KTB,” project. It was determined by the KTB team that to minimize some of the project’s inherent risks (high friction, not reaching the desired depth, stuck pipe, etc.), this well would have to be drilled as close to “absolutely vertical” as possible. As conventional directional drilling techniques were deemed unable to achieve this goal, a new automated drilling system had to be developed.

Funded by the German government, Baker Hughes INTEQ commenced development of the Vertical Drilling System (VDS) in October 1988. This new technology was designed to automatically maintain verticality while drilling using an autonomous closed-loop steering system.

While undergoing continuous improvement, the VDS was used to drill the KTB well to a vertical depth of 24,600 ft (7,500 m), with less than 40-ft (12-m) lateral displacement. At this point, the temperature exceeded specification of the VDS, so conventional drilling methods were used from that point on – and the well trajectory immediately started to deviate from vertical. The well was finally TD’d at 29,564 ft (9,011 m). The success of this scientific well was largely attributed to the automated closed-loop steering control of the VDS.

In 1993, INTEQ commenced a joint project with Eni/Agip called the Ultra Deep Horizontal Drilling (UDHD) project. The objective was to develop the steering technology required for drilling deep horizontal wells.

The outcome of the UDHD project was the development of VertiTrak system for use in vertical hole sections and the first AutoTrak Rotary Closed Loop Steerable (RCLS) system for use in deviated hole sections. Using high-density, near-bit inclination data from a real well, Figure 1 shows how the AutoTrak system’s closed-loop steering control precisely positions wells for maximum production and recovery with lower operational risk.


Through extensive experience with these type of systems, automating directional drilling control has proven to deliver enormous benefits. These include time and cost savings, more productive wells placed more precisely in the reservoir, improved hole quality resulting in fewer problems, greater reach and ability to drill complex, 3D well profiles to tap otherwise stranded reserves.

Another benefit of automating directional drilling is that it allows the directional driller to focus more attention on monitoring other aspects of the drilling operation, thereby using their experience to optimize the entire process. Figure 2 shows an example of how AutoTrak systems were used to precisely steer a complex, seven-branch, multilateral well through a very thin North Sea reservoir to increase recovery.

The advantages of the automated closed-loop control steering control is also widely recognized in extended-reach drilling (ERD) applications. By drilling a low-tortuosity, highly accurate wellpath, intersection of distant targets is achieved at lower operational risk. To date, at least 15 of the world’s top 20 ERD wells (described by either reach or measured depth) have employed automated rotary steerable technology. This includes the new ERD record on well Z-12 from Sakhalin Island, which was drilled to 38,322 ft (11,680 m) MD. Using leading-edge technologies, this well was drilled in half the time it would have taken if drilled conventionally. Figure 3 shows the world’s top 20 wells, with the bars shown in blue indicating those that utilized the automated closed-loop steering control.

Wider Implementation

As a direct result of the successes attained, this unique closed-loop steering control system has been implemented in other drilling systems for application in a wider range of well types.

Operators drilling in locations where reservoir size, production rates and/or rig spread costs are relatively low must tightly constrain drilling costs to ensure economic viability.

One technology introduced for this market is the TruTrak system, which incorporates closed-loop steering control for application on relatively straightforward, low-angle well profiles. The system combines downhole steering and an integrated downhole motor for improved efficiency and directional control in slide drilling applications. Bringing closed-loop steering control to these wells has enabled operators drilling these wells to reap many of the benefits previously only commonly attained offshore in higher spread cost applications. These benefits include time savings, more precise directional control and improved wellbore quality.

The system was used to drill a well onshore in North Texas having an “S”-shaped profile with 8º tangent section. Low-angle wells of this nature can be difficult and time-consuming to drill as they are not particularly suitable for conventional directional drilling techniques. Using an automated closed-loop control system not only saved time compared with similar offset wells but also helped to ensure the well was drilled accurately to plan.

An additional benefit was verified when the calliper run confirmed the well was of higher quality compared with conventionally drilled offsets.

Figure 4 shows the calliper log of the well compared with a similar offset well in the same area. The higher hole quality reduces torque and drag while drilling and allows easier casing running and cementing operations.

Still, while this system performed well in specific, low-angle profiles, many of the operators in these lower spread cost environments have been challenged to drill more complex wells to access smaller targets, reduce environmental impact, drain tight unconventional reservoirs or improve overall field recovery.

From a technical perspective, rotary steerable systems are frequently cited as the optimal solution. However, the costs of proven rotary steerable systems, including the integrated downhole LWD sensors and surface support requirements, make them difficult to justify given the field economics. To address this, a cost-effective base level AutoTrak RCLS service has been developed. This AutoTrak eXpress service uses the same closed-loop steering principle of the full-blown version, but with functionality tailored for use on more cost-sensitive projects. On a recent well in Oklahoma, this new system was able to drill a three-dimensional 8 ½-in. hole section in a single run from shoe to TD. The ROP was 20% higher than the best straight hole offsets drilling the same interval. Drilling the section in a single PDC bit run was equally impressive as it normally takes two to five bits to complete the section conventionally.

In addition to demonstrating an advantage over conventional drilling programs, automated systems are beginning to gain a foothold in coiled tubing applications. Directional drilling using coiled tubing is a highly efficient technique to apply in depleted or otherwise marginal developments. However, due to the flexibility of the tubing, these applications face the ongoing challenge of maintaining the desired steering control. This limits the precision of target intersection as well as the distance that wells drilled on coil can reach.

To address this challenge, INTEQ developed the CoilTrak system. Incorporating closed-loop steering control, toolface is maintained automatically within a small fraction of a degree. Literally steering the well from surface using a joystick, closed-loop automation provides pinpoint accuracy in wellbore positioning for optimized production and recovery.


Automation of the directional drilling process was achieved by building the autonomous systems into the downhole tool. With the exception of transmitting required trajectory changes from surface, the entire closed loop control had to operate autonomously downhole. The reason for this was the bandwidth limitations on data transmission between downhole and surface. To broaden application of automation to other drilling processes, a significantly higher rate data link is needed between surface and the downhole tools.

First trialed in 2003 and commercially launched in 2006, GrantPrideco’s IntelliServ Network provides a broadband data link between downhole and surface drilling systems via wired pipe. It is predicted by many that this is the enabling technology required to stimulate development of a significantly broader range of automated drilling processes. The goal will be increases in safety, efficiency, reliability and productivity. The system has already been used in conjunction with an automated pressure control system to drill a well offshore in Asia. In this well, the 20-in. casing shoe was set in weak formation, and the following hole section was anticipated to contain shallow gas. The combination of weak shoe and risk of a kick would normally have deemed this well too high-risk to drill.

This section was successfully drilled by linking, via the wired pipe, the annular pressure measurement from the MWD system with an automated choke system to provide closed-loop control of dynamic bottomhole pressure. Using this system, downhole pressure was maintained within 15 psi while drilling ahead and within 45 psi on connections – well within the identified safety margin. This well, which would have been impossible to drill safely without closed-loop pressure control, provides just a glimpse of applications which will become automated to meet our industry’s future demands.


Automating directional drilling was initially developed almost 20 years ago to meet the specific demands of a challenging scientific project. The benefits were clearly recognized, and automation was rapidly developed and deployed to the wider drilling industry with great success. The benefits are now widely publicized and accepted. In many cases, this capability allows wells to be drilled and whole fields to be developed that otherwise would have proved impossible either from a technical or economic perspective.

It is anticipated that automation will feature in an increasing number of drilling related activities to improve safety, efficiency and productivity. Simultaneously, automation will help deliver wells in the wider range of reservoir types requiring exploitation in the future. We have already seen initial glimpses of this as illustrated by the otherwise “impossible to drill” well offshore Asia. Coupling existing LWD systems to surface systems via faster telemetry systems helps open the door to development of the “next generation” of automation which many in our industry believe is required.

Jon Ruszka is a product line manager with Baker Hughes INTEQ, where he has held various technical and operational positions related to directional drilling services. He specializes in the development and application of advanced drilling systems. He holds a BSc (Hons) in aeronautical engineering from Bristol University, UK, and a pstgraduate diploma in offshore engineering from RGIT, Aberdeen, UK.

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