A 100% fully mechanical rotary-steerable tool has been developed specifically for the high-volume drilling market, providing full 3D directional control while under full rotation of the drillstring from surface. This durable push-the-bit rotary-steerable system (RSS) has eliminated the costly and sensitive electronics common to most RSS tools and has eliminated a number of vibration-related failure modes, making it suited for applications where shock and vibration are prevalent and for high-temperature applications.
Introduction
With the introduction of the downhole drilling motor in the 1980s, horizontal drilling became much more feasible. Horizontal wells are now the most common well type drilled in the US. Successful horizontal wells rely on accurate placement of the wellbore inside the desired reservoir. To achieve this, a directional driller is provided with drilling targets on a well plan, which are typically selected on the basis of offset-well information, seismic data, and geological models.
In an effort to optimize production while minimizing the number of rig moves and wells drilled, horizontal wells have stepped out farther and farther. As the horizontal displacement of a wellbore increases, torque and drag become major obstacles that must be overcome to enable efficient drilling. RSS tools provide a means to extend the wellbore beyond a steerable motor’s capabilities, but they come at a price that is often not economically feasible for the high-volume market. This forces operators to drill complex wells with either standard steerable motors or to pay for expensive RSS tools that challenge the economic viability of the well.
Drilling With Motors. Drilling with steerable motors has been the backbone of directional drilling since the 1980s. However, steering the wellbore with a motor requires slide drilling, which slows down drilling, reduces hole cleaning, and potentially creates other problematic conditions. Rate of penetration (ROP) is reduced when sliding because of friction between the borehole wall and the bottomhole assembly (BHA) as well as hang-up of drillstring components. Without drillstring rotation, the drilling mud is not agitated, allowing the cuttings to collect on the low side of the wellbore and potentially pack off the BHA.
The steerable motor contains a bent-housing section. When sliding, the bent housing has to be maintained in the desired direction, or tool-face setting. This can become difficult because of the reactive torque produced by the motor itself when the bit is on bottom. The reactive torque turns the drillstring in a counterclockwise direction, working against the directional driller and making it difficult to maintain control.
Reactive torque is a function of the formation being drilled, the bit type, and the motor output. It can be mitigated by use of lower-torque-rated motors, light-set polycrystalline-diamond-compact (PDC) bits, or roller-cone drill bits; however, all of these solutions result in lower ROPs. Although PDC-bit designs have advanced and many bits incorporate depth-of-cut-control technology to reduce reactive torque while sliding, the basic inefficiencies still remain.
Rotating steerable motors also can result in inefficient drilling. When rotating a motor, there is no directional control, and the BHA will wander on the basis of formation push, formation dip, bit type, stabilizer placement, and drilling parameters, resulting in the wellbore deviating from the target line. Once the wellbore is off plan, a slide has to be performed to reorient the wellbore to the target.
In addition, steerable motors can cause hole spiraling and an overgauge hole. This results from rotating a motor with a bend in it, and the larger the bend setting on the motor, the more eccentric the rotational pattern will be. This creates a spiraling hole gauge larger than the actual bit diameter, which can create poor-quality imaging logs because of the uneven wellbore walls.
Finally, transitioning from sliding to rotating and vice versa can create kinks in the wellbore known as doglegs. Doglegs are measured in degrees of deviation per 100 ft, or degrees of deviation per 30 m. Higher doglegs result in higher drag because the rest of the BHA and drillstring is forced through the dogleg. The sum of doglegs in a given wellbore is usually expressed as tortuosity. Another type of tortuosity is microtortuosity, which represents the “unseen” doglegs in the wellbore, such as what the BHA generates between survey intervals. The higher the tortuosity and microtortuosity of a wellbore, the greater the torque and drag that will be experienced while drilling, causing weight-transfer problems and making it more difficult to run casing or liner after drilling is completed.
As horizontal sections of the wellbore increase in length, the friction from the drillstring and BHA dragging against the low side of the hole increases to the point at which it is nearly impossible to transfer weight to the bit while trying to slide with a steerable motor. At this point, rotating the drillstring may be one of only a few available ways to transfer weight to the bit successfully. When rotating with a steerable motor, all directional control is lost, so if the formation pushes the BHA off path, total depth will have to be called early because of the motor’s limitations.
RSSs. RSSs were introduced to the drilling market in the mid-1990s and allow full directional control of the wellbore while rotating the drillstring at surface. Without the need for slide drilling, ROP is increased, hole cleaning is more efficient, and torque-and-drag issues are reduced dramatically, creating better weight transfer to the bit. Other benefits of RSSs include smoother wellbores, better directional control, more-accurate well placement, and extended lateral sections.
There are two basic types of RSSs, which work either by deflecting the bit shift, known as “point-the-bit” tools, or by pushing off the wellbore wall, known as “push-the-bit” tools. Regardless of the type of deflection, most RSS tools steer by use of an electronics package to control the basic functions of the tool. The electronics receive commands from the driller through cycling of the mud pumps or by varying the flow rate in a preprogrammed sequence. Through these flow-rate algorithms, the tool is told in which direction to steer. Besides steering, the electronics also allow an array of other options and features if the operator so desires. These features can include real-time near-bit measurements such as near-bit inclination and azimuth readings, gamma ray readings, temperature readings, shock and vibration measurements, tool-face settings, and downlink confirmations.
The advanced technology available in today’s RSSs has opened an entirely new scope of drilling. Of course, this premium technology comes with an extremely high price tag compared with standard steerable motors. Even with the added costs, RSS technology is preferred among operators in the deepwater market because of the increased ROP and the peace of mind that comes from knowing that casing issues and stuck-pipe events are minimized. The use of RSSs reduces the overall days in the ground and saves considerable costs off the high spread rate of deepwater drilling rigs, making an RSS a viable solution in these operations.
Although RSSs have proved quite popular in deepwater markets, their adoption into high-volume markets has been limited. As previously discussed, RSSs are complex drilling tools with sensitive electronics, and they come at a high cost. High temperatures and downhole vibrations can damage the electronics and render the tool inoperable, incurring great costs and possibly causing the tool to quickly steer off in the wrong direction, requiring the rig to sidetrack the wellbore. In the event of a lost-in-hole (LIH) situation, the charges for a rotary-steerable tool can be so high that the risk of losing one outweighs the benefits of running it.
Lateral-Drilling System (LDS)
The LDS is a 100% mechanical tool that provides 3D directional control while under full rotation of the drillstring. The LDS provides all the drilling benefits of a standard RSS tool without the need for costly and sensitive electronics, significantly increasing tool reliability and reducing operating charges, LIH costs, and repair charges. The LDS works as a push-the-bit RSS. It uses engineered stabilization to create a side force at the bit, causing the bit to steer in that direction. The side force comes from an offset stabilizer located on a nonrotating orientation housing behind the bit; the offset pushes the stabilizer into the borehole wall, and the bit will drill in the opposite direction. A detailed view of the LDS, showing the orientation housing and other components, is shown in Fig. 1 above.
In order to maintain a fixed tool-face reference point while drilling and orienting, the tool requires a fixed section that remains geostationary in relation to the drillstring rotation, as with electronics-based RSS tools. Because the LDS does not contain electronics, it does this with an eccentric-mass section known as the mass housing. The mass housing is connected to the orientation housing and contains high-density tungsten carbide weights along one side of the collar, which ride the low side of the wellbore and are heavy enough to prevent the mass housing from rotating while downhole. The BHA above the LDS is connected to the tool at the upper mandrel, which passes through the center of both the mass housing and the orientation housing, transferring the drillstring rotation to the bit.
When drilling on bottom, the drillstring rotates the bit through the mandrel running through the tool and the orientation housing (and tool face) is locked in position by the pressure drop created across the bit. During this time, the LDS will steer in the set direction with a consistent rate of curvature. When the pumps are shut down, a drive mechanism within the tool is engaged inside the orientation housing and the tool face can be oriented by rotating the drillstring at surface. As the drillstring is rotated with the pumps off, the orientation housing will advance the position of the offset stabilizer.
The tool-face location can be determined by counting the number of drillstring revolutions on surface, with each drillstring revolution correlating with how many degrees the tool face advances downhole on the basis of the gear ratio within the orientation housing.
If the tool face is ever in question, the tool can be reset by shutting down the pumps and rotating the number of drillstring revolutions required to return the offset stabilizer to its initial starting position. When the tool reaches this reference point, the internal drive mechanism switches into a neutral position and stops the orientation of the stabilizer. The pumps are then cycled on and back off once to re-engage the drive system inside the tool, and the tool face can then be oriented from the reference position. This simple and robust design allows the tool face to be changed in less than 3 minutes, and this can be performed at any time from the surface.
For a discussion of case studies featuring use of the LDS, please see the complete paper.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166717, “Fully Mechanical 3D Rotary-Steerable Tool Brings RSS Performance to the High-Volume Drilling Market at a Fraction of the Cost of Conventional Rotary-Steerable Tools,” by K. Hershberger and D. Herrington, NOV, prepared for the 2013 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, 7–9 October. The paper has not been peer reviewed.