Directional/complex wells

New Rotary-Steerable System Delivers High Dogleg Severity, Improves Penetration Rate

A new rotary-steerable system (RSS) was designed to give geometrically greater dogleg-severity (DLS) capability while still being able to withstand the increased bending stresses.

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A new rotary-steerable system (RSS) was designed to give geometrically greater dogleg-severity (DLS) capability while still being able to withstand the increased bending stresses. This high-build-rate RSS was able to eliminate controlled rate of penetration (ROP) as a limiter, which resulted in 39% ROP improvement. In addition, the development of a high-build-rate RSS provided multiple benefits, including elimination of ROP and logging-while-drilling limitations, increased curvature capabilities, and higher reliability of the system with respect to high-bending-related issues.


Directional-Drilling Methods. In the early days of directional drilling, the process involved jetting and the use of bent subs as the main methods for deviating a wellbore. These methods largely have been superseded by the use of engineered bottomhole assemblies (BHAs) for inclination-only control and motor or rotary-steerable BHAs for complete 3D control.

Simple BHAs (Inclination Control). In simple BHAs, placement of stabilizer elements determines the net force on the bit and results in either a building or a dropping tendency of the BHA.

A stabilizer placed close to the bit acts as a fulcrum, with one side being forced down by the weight of drill collars. Because of this, the bit will drill along a path of increasing inclination and the BHA will have a tendency to build angle.

On the other hand, a stabilizer placed significantly away from the bit will cause the collars below to sink to the low side of the borehole, pushing the bit to drill a path of decreasing inclination. This BHA will have a tendency to drop angle.

A BHA designed to maintain direction will have stabilizers placed so as to create a rigid BHA, which will not bend in any direction with the force of gravity, causing the bit to drill along a straight path.

Motor BHAs (Full Directional Control). Mud motors are used routinely to drill directional wells. They consist of a power section that converts mud flow into rotational movement of the rotor. The directional control is derived from an integral bent housing that can be adjusted to provide various bend angles. The higher the bend, the greater the capability to drill in a given direction, providing greater DLS. In this mode, the drillstring is kept stationary and the bit is rotated through the action of the motor only.

To drill in a straight line, the complete assembly is rotated, which results in a tendency to drill along a relatively straight path. To drill in a particular direction, the motor bend is pointed in the given direction and weight is applied on the bit. This will result in the bit being tilted from the hole axis in the direction of the bend and in the formation being cut in that direction, thus achieving the required trajectory.

Because the bend needs to be pointed in the direction of the turn, the motor BHA is not rotated when drilling.

RSSs (Full Directional Control). RSSs achieve directional capability by creating a bend near the bit while the BHA is rotating.

The most common type of RSS works on a point-the-bit or push-the-bit principle or a hybrid of both.

Point-the-bit systems create the required bend through an internal mechanical or hydraulic arrangement that tilts the bit in the required direction. Push-the-bit and hybrid systems, on the other hand, create the bend by pushing against the formation and bending the BHA in the required direction. Both systems are required to achieve this while the BHA is rotating.

Geometrical DLS Capability. Any directional-drilling BHA will need to have the bit tilted relative to the main BHA axis to be able to drill in the given direction. The tilt angle and distance between the first three contact points (Fig. 1) determine the maximum DLS achievable by the BHA. These values will determine the geometrical limit that the BHA can achieve by design. By reducing the distance between the contact points while maintaining the same tilt, the DLS capability of the BHA will be increased.

Fig. 1: Three-point geometry.


In addition to geometrical constraints, the formation hardness will play a key role in determining whether the maximum geometrical DLS  is achievable. A formation that is washed away by mud flow will have different geometry and will achieve lower DLS. Very hard formations will not allow easy penetration and will cause the actual DLS to be lower than the geometrical prediction.

When the required DLS is not being achieved, the standard procedure is to slow down the ROP to allow the bit to cut in the required direction at its maximum. This reduces the forward movement, and, with maximum side cutting, a DLS can be achieved up to the geometrical limit.

Drilling 8½-in. Section With the Required DLS

Drilling 8½-in. hole required building from vertical to horizontal in approximately 2,000 ft of section length. The build section consisted of a large shale sequence of varying properties. In some zones, it is easier to build angle; in other zones, properties limit the achievable DLS. The well-plan requirements called for an average DLS of 5°/100 ft or greater for this section.

Using previous drilling experience, the planned well path in these wells was adjusted to achieve greater DLS in the beginning and later parts of the section and the required DLS was reduced in the middle. This resulted in maximum planned DLS of 7°/100 ft in some sections and 2–3° in other parts of the 8½-in. section.

All these factors resulted in a planned and drilled well path that had high variation in DLS along its 8½-in. section. Almost every well had some 8½-in. section where the required DLS challenged the available tool limits and where failure to deliver the DLS meant that a plugback might become necessary.

Standard 8½-in.-Section RSS BHA Performance

This section was traditionally drilled with an RSS with a logging BHA consisting of gamma, resistivity, neutron, and density tools. The standard BHA was optimized with a flexible stabilizer sub that would stabilize the RSS while maintaining enough flexibility to deliver the required DLS.

Because of the formation characteristics, it was sometimes necessary to control ROP to allow the RSS to achieve the required DLS. This was also the case if the formation tops were detected to be shallower during drilling and an early landing of the well had to be performed. Drilling with a controlled ROP to achieve the require DLS was identified as a performance limiter. Given that there was no other reason to control ROP, if DLS could be achieved without controlling ROP, an improvement of greater than 50% could be achieved.

Improved Steering-Unit Design

Considering the ROP limitation imposed by the DLS requirements, it was determined that a different design with higher DLS capability was required. With the higher DLS capability, the tool could achieve the required DLS without controlling the ROP.

Two possible scenarios existed for increasing the DLS capability:

  • Make the current BHA more flexible so that small forces at the bit could create greater BHA deflection and thus greater DLS.
  • Increase the geometric DLS capability by changing the BHA components and placement to create a high-DLS-capable configuration; this could be achieved by reducing the distance between the bit and the contact points behind it (i.e., stabilizers).

The flexibility option was discarded because it was determined that the current BHA was already quite flexible and any more reduction in rigidity would increase the extent of damaging vibrations. The focus was then placed on increasing the geometric DLS capability.
A high-DLS-capable RSS already had been released for the US land market capable of delivering a DLS of up to 15°/100 ft because of its geometrical design. The design placed the three contact points closer to each other, thus allowing a significantly greater DLS capability. The design and components were engineered to deliver the required DLS and were rated to withstand stresses at these high DLSs. The steering unit of this new RSS could be integrated into a standard BHA and could be used to deliver the advantage of a greater geometrical DLS capability.

A review of this application was performed, and the BHA was analyzed on ­finite-element software to determine

  • That the required DLS could be achieved consistently without controlling the ROP
  • That the BHA components would not be stressed beyond their rated stress limits

It was concluded that the application had a good chance of success. There was little risk because all of the components had been proved through previous use.


Consistently higher on-bottom ROPs were observed when the new RSS was used to drill the 8½-in. sections. The incidence of controlled ROP fell to a minimum, and forces required to achieve required DLS dropped significantly.

Another benefit was that wells could be planned with a consistent DLS because high DLS was now achievable throughout the section.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177836, “New Rotary-Steerable Drilling System Introduction in the UAE for ADCO Delivers High DLS Capabilities While Improving ROP and Providing Extensive Formation-Evaluation Data,” by Imran Tipu, Shurooq Abdulla Mohamed Al Jasmi, Juma Sulaiman Al Shamsi, Ali M. Danche, and Muhammad Javid, Abu Dhabi Company for Onshore Petroleum Operations, and Jehanzeb Nurzai, SPE, Enrico Biscaro,SPE, and Nour Shat, Baker Hughes, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9–12 November. The paper has not been peer reviewed.