Rotary steerable system replaces slide mode for directional drilling applications

March 2, 1998
A new rotary steerable system combines the drilling efficiency advantages of rotary assemblies with the course control associated with bent-housing motor techniques. The system's downhole computer can automatically guide the tool along a planned well path, and two-way communication between surface operators and the downhole assembly permits adjustments to system parameters and the well path without interrupting the drilling process.
Jonny Haugen, Baker Hughes
A new rotary steerable system combines the drilling efficiency advantages of rotary assemblies with the course control associated with bent-housing motor techniques.

The system's downhole computer can automatically guide the tool along a planned well path, and two-way communication between surface operators and the downhole assembly permits adjustments to system parameters and the well path without interrupting the drilling process.

The system also incorporates logging-while-drilling (LWD) sensors, placed close to the drill bit, which give it advanced geosteering capabilities. The technology was developed in conjunction with a major oil company, then refined during an accelerated field test program.

Commercial rotary steerable applications have shown economic improvements over conventional sliding/rotating applications. Improved efficiencies in the drilling process and the elimination of sliding have tripled penetration rates and provided cost savings of $300,000 on Statoil's Statfjord platform. In southern Italy, penetration rates in hard formations have also improved 33% in Agip's Monte Enoc field.

Steerable motor systems

During the late 1980s, directional drilling methods were transformed by the introduction of steerable motor systems. These systems use positive-displacement mud motors to turn the drill bit independently of drillstring rotation. A slight bend in the motor housing imparts a bit offset that is oriented to turn the well in the desired direction.

A measurement-while-drilling system monitors the well's azimuth and inclination as well as the direction of the bend (tool face). It sends these measurements to the surface via mud-pulse telemetry. To change the well's course, the tool face is oriented by turning the drill pipe from the surface, then holding it at the correct heading.

In a process called sliding, the drilling assembly is pushed along a curved trajectory defined by the bend in the motor, the drill bit, and the tool's stabilizers. To drill a straight well course, the driller rotates the drillstring from the surface as the downhole motor continues to run.

Drillstring rotation negates the bit offset in the steerable motor, resulting in a straight course with a slightly over-gauge hole.

Steerable motor systems gave directional drillers unprecedented control over the well's course. With these tools, build-up rates of up to 30°/100 ft could be achieved, and well designs, including simultaneous builds and turns, could be accomplished efficiently for the first time.

The required number of bottom hole assembly (BHA) changes was reduced considerably compared to previous rotary methods, and directional drilling became based more on engineering principles than on empirical art learned through lengthy field experience. Steerable motor systems enabled the industry to introduce and refine horizontal drilling so that horizontal wells now are drilled routinely throughout the world.

Despite all these advantages, engineers soon began to recognize the shortcomings of directional drilling using steerable motors and that slide drilling has inherent shortcomings.

While sliding, penetration rates are reduced by as much as 50% as compared to drilling with string rotation. Hole cleaning also can be a problem. Without rotation, cuttings can accumulate on the low side of horizontal and high angle holes, contributing to drillstring friction and increasing the risk of stuck pipe.

During slide drilling, it can be difficult to maintain constant bit weight. This slows penetration rates and imparts axial shocks that can damage the BHA as the drill bit repeatedly tags bottom as weight is applied. Downhole motor sliding produces reactive torque. Because of this, it is often hard to maintain the proper tool-face heading.

To compensate, drillers frequently opt for roller-cone bits instead of more aggressive polycrystalline diamond compact (PDC) bits. This sacrifices penetration rates, increases the number of bit trips because of short roller-cone bit life, and increases the risk of bit failure in return for better directional control.

Finally, slide drilling eventually encounters friction and drag limitations that may impede reaching total depth in extended reach wells. Accumulated friction along the extended reach well bore prevents effective tool face orientation and prohibits transfer of weight to the bit without drillstring rotation.

Steerable motor systems also can cause problems during drillstring rotation. Because eccentric BHAs are rotated while drilling ahead, they end up drilling an over-gauge hole. When drilling operations shift from sliding to rotation, the change in hole size causes transition ledges that may collect cuttings and cause stabilizers to hang-up.

The bent motor assembly also tends to drill a spiral hole during rotation. This contributes to well bore tortuosity, increases friction on the drillstring, and limits total displacement of the well.

Because of these limitations, drilling engineers have designed their well paths to suit the capabilities of available steerable systems, and technology developers have worked to invent new rotary steerable drilling systems.

These new systems would combine the precise directional control of steerable motors with the high penetration rates, hole cleaning advantages, and reduced friction of rotary drilling techniques.

Information technology also would be incorporated into the system to further enhance hole quality and to enable operators on the surface to control the system's parameters without interrupting the drilling process.

Vertical drilling system

In the late 1980s, scientists at the Continental Deep Drilling (KTB) project in southern Germany drilled an experimental well deep into the earth's crust. With an objective of 9,000 m true vertical depth (TVD), the KTB well had to be kept within 1° of vertical for its entire depth to limit friction on drilling and casing strings and to avoid exceeding the experimental rig's hoisting capacity.

Engineers at Eastman Christensen GmbH designed, built, and operated a vertical drilling system for the KTB project. The vertical drilling system included a near-bit inclination sensor and a downhole processor programmed to activate steering ribs on a stabilizer just above the bit.

Powered by an hydraulic system, the ribs created side forces against the borehole wall to continually nudge the well back to verticality in a closed-loop process. During the 4-year project, ongoing design improvements were implemented as the vertical drilling system logged more than 4,000 hr of operation.

In part, because the system controlled the well within ±0.3° of vertical, the KTB project reached its target depth in highly crystalline rock. With success in a vertical application, drilling systems developers realized that steering pads activated using a closed-loop system also could be applied to directional drilling.

Operator involvement

In 1993, Agip S.p.A. and Baker Hughes Inteq initiated a joint development program that would use concepts proven during the KTB project to develop a new rotary-steerable drilling system ( Fig. 1 [42,394 bytes] and Fig. 2 [12,432 bytes]). The new system is called a rotary closed loop system (RCLS) because it is capable of closed-loop decision making to control a well's inclination and azimuth ( Fig. 3 [147,671 bytes]).

After initial evaluation, the development team decided to focus on three major subsystems:

  1. Surface-to-downhole communications-This enables system operators to send commands to the system as drilling continues.
  2. Directional steering unit-This controls azimuth and inclination during drillstring rotation using automated steering techniques that do not require intervention from the surface
  3. LWD module-This contains formation evaluation sensors in close proximity to the bit permitting precise geosteering and wireline replacement logging.

Surface-to-downhole communications

For the past 20 years, MWD systems have operated successfully using mud-pulse telemetry to achieve downhole-to-surface communications (uplink). Formation evaluation, temperature, directional, pressure, and system status data are thus transmitted from the MWD tool to the surface. This method is used for the uplink in the rotary steerable system.

With the addition of surface-to-downhole communications (downlink), operators could control the tool from the surface and broaden its functionality by redirecting its course or by selecting different data sets to be sent to the surface.

To achieve the downlink, project engineers developed a new technique that uses flow-rate modulation to transmit commands from the surface to the downhole tool. From there, an on-board computer demodulates the command data and changes system operation without interrupting the drilling process (Fig. 4 [41,231 bytes]).

The downlink capability brings a new, higher level of control to the system operator. For example, commands can activate and deactivate electronic modules in the downhole tool; alter the system's data rate; communicate new inclination and azimuth objectives; vary build, turn, or drop rates; and change other operating variables.

Directional steering unit

The steering unit is a nonrotating steerable sleeve, uncoupled from the drillstring, whose extendible pads press against the hole wall as the drive shaft-connecting the drillstring to the bit-turns inside it ( Fig. 5 [11,206 bytes]). Housed in the nonrotating sleeve are the bit inclinometer, steering control electronics, and control valves for the hydraulically extendible stabilizer pads.

The system applies a different, controlled hydraulic force to each steering rib. The resulting force vector directs the tool along the desired trajectory (Fig. 6 [40,665 bytes]). This force vector is adjusted by a combination of downhole electronic control and commands pulsed hydraulically from the surface.

Deviations from the programmed inclination are automatically compensated for through closed-loop control. Commands to adjust the well path can be downlinked while drilling continues.

The steering unit's hydraulic system operation with variable oil pressure regulation and the turbine-driven oil pump were proven in extensive laboratory tests in Germany and Italy. During field tests, the nonrotating sleeve actually was observed to rotate about 2-3 revolutions every half hour.

However, the closed-loop electronics continuously measures the relative position of the sleeve, and the hydraulic force applied to each steering rib is automatically adjusted to compensate for any rotation. The system can be set to two different steering modes while drilling.

The hold mode is associated with three parameters:

  1. Build or drop force
  2. Left or right walk force
  3. Target inclination.
The programmed build or drop force controls the dogleg severity until the desired inclination is reached. A walk-compensation force can be set to counteract formation or BHA influences on azimuth hold, or to turn the hole right or left. The steering unit can apply build/drop and walk forces simultaneously.

When the drilling assembly reaches the programmed inclination, the system will automatically enter into a hold position to maintain the objective until otherwise commanded by downlink.

Steer mode is an alternative method of controlling the well path by programming the steering force and steering direction, for example, the steering vector. This mode is similar to the method used with conventional steerable motors, with the steering vector equivalent to a tool-face orientation.

The uncoupled, nonrotating sleeve provides several operational advantages compared to steerable motor systems. The sleeve gives more precise control over the well's trajectory. In addition, bit side forces and hole dogleg are controlled continuously by the downhole closed-loop system.

Because bit-inclination measurements are taken in the absence of rotation and its related shocks, they enable highly accurate drilling, particularly for geosteering applications. With the nonrotating steering sleeve, drillers can select bits based on penetration rates in the formation rather than the steerability of the BHA.

Unique PDC bits that take into account the fundamental differences between the RCLS system and a standard positive displacement motor (PDM) assemblies have been developed, and successfully run.

Formation evaluation

Early in the project, system designers specified that the rotary-steerable system should have integral LWD capabilities that would permit both quantitative formation evaluation and precise geosteering. The desired LWD module also would link easily to a directional MWD system and other formation-evaluation sensors.

An existing resistivity measurement package, previously developed for a downhole motor-driven geosteering system, met all these design criteria. It was therefore incorporated into the RCLS tool. The reservoir-navigation module includes real time inclination sensors, dual azimuthal gamma-ray scintillators, and multiple-propagation resistivity sensors close to the bit (Fig. 7 [41,749 bytes]).

With these measurements, the new system can investigate the formation while drilling, collect and store large amounts of petrophysical data, and steer using real-time evaluation of the surrounding reservoir structure.

The dual azimuthal gamma-ray sensors, oriented 180° from one another, provide high-side and low-side measurements. Thus, they permit quick determination of whether a nearby bed boundary is above or below the tool.

The resistivity sensor is a two-frequency, compensated-propagation device that can operate in oil, synthetic, and water-based drilling fluids. Located above and below a receiver antenna pair, two transmitting antennas sequentially broadcast at frequencies of 2 megahertz (mhz) and 400 khz.

With this resistivity sensor array, the system provides deep-reading 400 khz measurements and high vertical-resolution, 2 mhz readings. This combination is especially useful in geosteering applications. When drilling horizontally, the 400 khz reading can detect a contrasting bed boundary or fluid contact up to 5.5 m (18 ft) from the sensor.

This enables drillers to anticipate boundaries 75-150 m (250-500 ft) ahead of the bit and signal the rotary steerable tool to adjust the well's course to stay within the target zone.

Field test program

After favorable results were achieved in the laboratory, the RCLS technology entered an intensive field-test program. Early testing, carried out at a drilling test facility in Montrose, Scotland, demonstrated that the newly designed steering unit could control the well path's direction and build rate.

It proved that the surface-to-downhole communications method could redirect the downhole tool to a new directional objective. During this phase, the project team made several design improvements, particularly in the mud oil sealing system.

The next series of tests, during the second half of 1996, included one well in Northern Italy and four offshore wells in the Adriatic Sea. On Agip's Gisolo well No. 1, a rotary steerable system prototype proved its ability to hold a preprogrammed inclination by staying within 0.3° of plan throughout a 67-hr run.

On the Regina 2 offshore well, two rotary steerable assemblies drilled an 859-m section of hole, building inclination from 20° to 48° with an average penetration rate of 35 m/hr. Throughout this section, the system kept the well's trajectory within a maximum of 5 m from the planned well path.

After the test, algorithms used in the downlink process were modified to improve communication with the downhole tool and to tighten the precision in well-path control. In addition, improvements in the pulser and mud oil sealing system designs were made after the test.

The complete 81/2-in. hole section of the Clothilde No. 1 offshore well was drilled with a single rotary-steerable tool. The system drilled 1,230 m in 25 hr, building inclination from 25° to 50° with a build rate of 3.5°/30 m. The run included a 900-m hole section that was held to the planned 50° inclination.

The high penetration rates of 47 m/hr demonstrated the tool could drill efficiently even while steering. Based on changes made after the Regina well, the sealing system and downlink communication showed significant improvement. However, the well path strayed as much as 13 m from the planned trajectory, and subsequent corrections were considered too sharp.

The project team therefore began further modifications to the system control algorithms and software. This work proceeded as the next test well was drilled.

The next two wells were drilled to much deeper objectives and were considered the most demanding trials to date for the new rotary steerable system. On the Antonella No. 11, two tools drilled a total of 953 m (3,127 ft) in 41.7 hr of drilling. The first tool achieved instantaneous penetration rates of up to 130 m/hr while rotating at 150 rpm with 8 tons on the bit.

Toward the end of its run, this tool began to drop angle and could not be redirected by downlink. At the surface, engineers found that a plugged oil filter in the hydraulic system had caused the failure. On the second run, the tool built angle as expected, but failed to decode a downlink command to change azimuth.

Project engineers believed that downlink software improvements already being implemented would prevent these problems on the next test well. Despite directional control problems, the system drilled 50% faster than stiff, conventional rotary BHAs used in the same formation.

On the final Adriatic test well, the Antonella No. 12, the RCLS drilled 934 m (3,064 ft) in a 72.5-hr run. With the software improvements, the downlink communication system proved very effective in initiating course corrections to hit the target.

Directional control was better than with steerable motor systems used on wells from the same platform, and penetration rates exceeded those for PDM, turbine, and conventional rotary assemblies.

In December 1996, an additional trial was performed as part of the Thermie advanced well project, located at Agip's test well site in Cortemaggiore, Italy. The rotary steerable tools kicked off from a cemented, vertical section, built inclination to almost 90°, then reached the horizontal target with excellent TVD control.

Using the surface-to-downhole communication link and the tool's downhole closed-loop capabilities, any deviation from the planned horizontal trajectory could be corrected within centimeters. Observed torque and drag were lower than anticipated, which was attributed to the smooth borehole drilled by the rotary steerable system.

In the total program of field trials, the new rotary steerable system was used to drill more than 8,000 m (26,350 ft) of 81/2-in. hole during 1,000 hr of downhole operation. Design objectives were achieved, so the tools were placed into pilot production and selective commercial operations.

Early commercial runs

Since the test program, the rotary steerable system has been run commercially on a number of wells in Norway, the U.K., and Italy. On Statoil's Statfjord platform, the system was used in a horizontal application. Software problems caused a failure on the first run.

Once these problems were corrected, a second tool was used to build inclination from 50° to 85.5° while turning the well from 204° to 217° azimuth. The tool decoded all downlinks correctly during this run, and once target inclination and direction were achieved, it drilled a 670 m (2,198 ft) tangential section with only minor variations in inclination.

Then operators programmed the tool to drop inclination to 76° to complete the run. At this point, the 81/2-in. hole was reamed to 95/8 in. to lower the equivalent circulating density of the drilling fluid and avoid formation damage in the reservoir section.

For the final hole section, another rotary steerable tool was programmed to build angle then hold inclination at 87.7°. During a 1,000 m (3,280 ft) run, the rotary steerable system followed the well plan with great precision and reached total depth.

The tool reduced drilling torque and drag, so that only 10 tons of bit weight were required by the rotary steerable system compared to 20 tons with a steerable motor system at similar depths. Statoil also noted improved cuttings removal and more consistent hydraulics than during intervals drilled with PDMs.

The operator estimated that the system's higher penetration rates saved 3.2 days of operating time for a cost savings of $330,000, compared to the historical average penetration rates for the past 4 years.

On Agip's Monte Enoc well in southern Italy, the rotary steerable system was used successfully on a 416 m (1,365 ft) section in a harder formation. The penetration rate was 3 m/hr compared to less than 2 m/hr in nearby wells.

Because of consistent bit weights applied to the RCLS, Agip was able to use a PDC bit in a formation normally drilled with roller-cone bits. This improved penetration rates and reduced trip time.

Ongoing development

As oil company engineers gain a better understanding of the capabilities of rotary steerable systems, they will design their wells with longer departures and more complex trajectories that intersect several targets. Ultimately, these systems could enable oil companies to develop offshore fields with fewer wells and fewer platforms.

As technology developers gain more experience with these new systems, they will design and build newer versions of the tool that will be less costly, while incorporating more sensors for drilling efficiency and formation evaluation.

Future rotary steerable systems also may use closed-loop control for the geosteering process. Resistivity and sonic measurements will detect bed boundaries and fluid contacts, and the system will automatically adjust the well's path to avoid them.

Eventually, these tools also may be programmed to interact with 3D seismic earth models to acquire more-detailed information about the reservoir and assure optimum well placement for long-term production management.


The author would like to thank Ron Bitto for his contributions to this article.


  1. Donati, Franco; Oppelt, Joachim; Trampini, Alessandro; and Ragnitz, Detlef, "Innovative Rotary Closed Loop System-Engineering Concept Proven By Extensive Field Application In The Adriatic Sea," IADC/SPE paper 39328, to be presented at the IADC/SPE Drilling Conference, Dallas, Mar. 3-6, 1998.
  2. Andreassen, E., Blikra, H., Hjelle, A., Kvamme, S.A., and Haugen, J., "Rotary Steerable System Improves Reservoir Drilling Efficiency and Well bore Placement in the Statfjord Field," IADC/SPE paper 39329, to be presented at the IADC/SPE Drilling Conference, Dallas, Mar. 3-6, 1998.
  3. Rich, Gary; Gruenhagen, Hartmut; Oppelt, Joachim; Donati, Francesco; and Trampini, Alessandro, "Rotary Closed Loop Drilling System Designed for the Next Millennium," Petroleum Engineer International, pp. 47-53, May 1997.

The Author

Jonny Haugen is a product manager for Baker Hughes Inteq. Of his 10 years oil field experience, he has been with Baker Hughes for 6 years, specializing in new products development and commercialization. He graduated from Sogn and Fjordane Regional College in 1988 and the Petroleum Geology University of Bergen in 1991 with degrees in geology and geophysics.

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