All shale operators share common well construction objectives in these challenging times of sub-$50 bbl oil. In their efforts to drill ever-longer laterals and improve the precision of wellbore placement, these operators need drilling solutions that can increase overall operating efficiency, reduce days on the well, increase overall wellbore stability and optimize well planning to allow tight well spacing. And they want to accomplish these objectives in one smooth, fast run.

Another common concern is that steerable motor drilling systems cannot create a precise high-quality wellbore and that longer laterals cannot be drilled due to an increase of torque and drag as the well length increases. In the past the operator might drill a sidetrack to bypass a problem area in the original wellbore and continue on to target depth (TD). But with the advent of multiwell pad drilling and the shift to tighter well spacing, a sidetrack might not always be a viable option. Increasingly, with tighter tolerances between wells there is little margin for error, which means the drilling system needs to get it right the first time.

Rotary steerable system (RSS) technology was developed precisely to address industry needs such as these and provide a system able to deliver precise wellbore placement, improved wellbore stability, reduced tortuosity, extended lateral lengths and improved overall operating efficiency.

An integrated solution

Baker Hughes embarked on a development program to deliver a comprehensive high-performance drilling package for unconventional wells. The service provider collaborated with operators in several major U.S. shale plays to develop a new drilling system that would allow the vertical, curve and lateral sections of a well to be safely, quickly and accurately drilled in one run.

The system would have to address the unique drilling challenges of each distinct section of the well:

  • In the vertical section the system would have to avoid tortuosity while drilling through interbedded formations and sections containing faults and dips;
  • In the curve section the system would need to deliver a consistently high buildup rate to reach the target production zone as quickly and accurately as possible; and
  • In the lateral section—in response to the market demand for longer laterals— the systems would have to be able to drill out to 3,000-plus m (10,000-plus ft) lengths while staying in the production zone.

To meet these challenges while also drilling multiple sections in the same run, the new system incorporates several key components—the RSS, drillbits, drilling fluids and solids control systems—into one fully integrated package. However, this system was not developed overnight but rather evolved over the course of several years in many different wells.

Putting the pieces together

The first step of the development process began with advancements to the RSS. The Baker Hughes Auto- Trak Curve RSS employs the continuous proportional steering methodology to constantly steer the well in the desired direction and to maximize horizontal reservoir exposure in wells with limited space. Unlike push- or point-the-bit RSS tools that are either on or off, this system has three pads mounted an equal distance from each other and are always working to keep the bottomhole assembly (BHA) steering in the right direction.

Continuous proportional steering works with any type of drillbit and does not require a particular type of drilling fluid to operate, nor does it need a minimum pressure drop across the bit to enable it to steer. This gives operators much greater flexibility than is available with other RSS tools to optimize all aspects of the downhole system and allows them to drill straight verticals, curves up to 15 degrees per 30 m (100 ft) and longer horizontal lateral sections in one run.

The AutoTrak Curve RSS also incorporates real-time near-bit inclination for holding tangents, buildup rate projection ahead, accurate landing projection and improved true vertical depth control during lateral drilling. Near-bit bulk and up/down gamma services improve formation navigation in long laterals, while real-time near-bit vibration monitoring sensors allow faster and more efficient drilling without compromising wellbore stability and tool reliability.

In 2011 the service provider was deploying a nonmotor- assisted rotary steerable BHA—almost exclusively— into South Texas, Oklahoma, Pennsylvania and Ohio shale plays. Operator demand for increased ROP in longer laterals prompted a shift to a motor-assisted BHA design. A directional drilling motor provided additional bit torque at lower speeds, which would minimize bit damage while drilling through hard and soft interbedded formations. The motor also was designed to provide additional downhole rotation speed at the bit and handle high differential pressures when drilling through high dogleg severity boundaries. Within two years the motor-assisted version was used on every new well the service provider helped to drill.

To realize the full performance potential of the motor-assisted RSS, Baker Hughes turned its attention to optimizing the design of the drillbit for each specific formation. Drawing on historical field experience and operator data, the designers considered dynamic and thermal stability, borehole quality, durability and hydraulics in each application. The bits were designed to match the torque, speed and steering mechanics of the RSS.

Setting footage records

The fully integrated system has been widely deployed in the Marcellus and Utica shale plays and partially integrated in Wyoming’s Denver-Julesberg (DJ) Basin. The system has evolved, with operators in these regions consistently achieving more accurate well placement in significantly fewer days.

In 2015 one operator in the DJ Basin commonly deployed a conventional motor-assisted system to drill the surface drillout to the lateral TD from 610 m to 4,877 m (2,000 ft to 16,000 ft). This system would require anywhere from 2.8 days to 4.6 days to drill these sections.

The integrated system was first deployed in January 2016, and it immediately dropped the average days on well to 3.6 to drill the same 610-m to 4,877-m section. By March 2017 the integrated system was drilling even longer wells in less time. One recent well was drilled to a TD of 5,443 m (17,857 ft) in 2.3 days. The record holder for this operator was a 5,405-m (17,733-ft) well that the integrated system drilled in just 1.95 days.

Operators in the Marcellus and Utica have since used the integrated drilling system to reduce their well costs, optimize well placement and improve operational efficiency. The system also allowed operators to reach TD with long multilaterals built from one common wellpad, a particular advantage in a region with physical space constraints and regulations that limit where a rig can be placed.

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