Directional deviation tools

The most common deviation tools for directional drilling are steerable motor assemblies (or so-called positive-displacement motors [PDMs]) and rotary steerable systems (RSSs). Adjustable-gauge stabilizers, known as “2D rotary systems,” have become quite popular to run with the rotary and PDM assemblies to control inclination. Whipstocks, especially casing whipstocks, are used routinely to sidetrack out of cased wellbores. Other tools, such as turbines, are used mainly in Russia, and jetting bits are seldom used today.

Steerable motor assemblies or PDMs

The most important advancements in trajectory control are the steerable motor assemblies, which contain PDMs with bent subs or bent housing. The PDM is based on the Moineau principle. The first commercial PDM was introduced to the petroleum industry in the late 1960s. Since then, PDM use has been accelerated greatly for directional-drilling applications. Steerable motor assemblies are versatile and are used in all sections of directional wells, from kicking off and building angle to drilling tangent sections and providing accurate trajectory control. Among the PDM assemblies, the most commonly used deviation tool today is the bent-housing mud motor.

The bent sub and bent housing use bit tilt (misalignment of bit face away from the drillstring axis) and bit side force to change the hole direction and inclination. Bent housing is more effective than the bent sub because of a shorter bit-to-bend distance, which reduces the bit offset and creates a higher build rate for a given bend size. A shorter bit-to-bend distance also reduces the moment arm, which, in turn, reduces the bending stress at the bend. As a result, the bent-housing PDM is easier to orient and allows for a long rotation period. Larger hole sizes (22 to 26 in.) are the only application for a bent sub. The requirement for bent subs is obsolete in most applications, particularly with the introduction of the adjustable bent housing.

Before the personal computer become widely available, the simple “three-point curvature” calculation was used to predict the build rates of the motor assemblies as

....................(1)

in which,

r_b = build rate in degrees/100 ft,

θ = bend angle in degrees,

L₁ = distance from the first contact point (bit) to the second (bend) in ft,

L₂ = distance from the second contact point to the third (motor top stabilizer) in ft.

For more-accurate results, a BHA-analysis program is often used to calculate the build/drop/turn rates of the motor assemblies. Fig. 1 shows the expected Dogleg Severity (DLS) and the bit side forces for a two-stabilizer motor assembly.

• 

  Fig. 1—The effect of the bent-housing angle on build rates and bit side load.

Bent-housing motor components

A typical bent-housing motor contains the following four sections: dump sub, power unit, transmission/bent-housing unit, and bearing section.

Dump sub

Located on top of the motor assembly, the dump sub contains a valve that is ported to allow fluid flow between the drillstrings and the annulus. This allows the drillstrings to fill when tripping in the hole and empty when tripping out of the hole. The dump sub also permits low-rate circulation bypassing of the motor, if required.

Power unit

Most motor assemblies use the Moineau pump principle to convert hydraulic energy to mechanical energy: a rotor/stator pair converts the hydraulic energy of the pressurized circulating fluid to mechanical energy for a rotating shaft. The rotor and stator are of lobed design. Both rotor- and stator-lobe profiles are similar, with the steel rotor having one less lobe than the elastomeric stator. The rotor and stator lobes are helical in nature, with one stage equating to the linear distance of a full “wrap” of the stator helix. Power units may be categorized with respect to the number of lobes and the effective stages. The speed and torque of a power section is linked directly to the number of lobes on the rotor and stator. The greater the number of lobes, the greater the torque and the lower the rotary speed. Typical rotor/stator configurations range from 1:2 to 9:10 lobe, as shown in Fig. 2. The power section should be matched to the bit and the formation being drilled for best performance.

• 

  Fig. 2—Typical rotor/stator configurations.

Transmission bent-housing/unit

The universal couplings inside the transmission/bent-housing unit eliminate all eccentric rotor motion and accommodate the misalignment motion of the bent housing while transmitting torque and down thrust to the drive shaft, which is held concentrically by the bearing assembly.

Bearing section

The bearing assembly consists of multiple thrust-bearing cartridges, radial bearings, a flow restrictor, and a drive shaft. The thrust bearings support the down thrust of the rotor, the hydraulic down thrust from bit pressure loss, and the reactive upward thrust from the applied WOB. For larger-diameter motors, the thrust bearings are usually of multistack ball- and track-design. Small-diameter motors use carbide/diamond-enhanced friction bearings. Metallic and nonmetallic radial bearings are employed above and below the thrust bearings to absorb lateral side loading of the drive shaft. The flow restrictor allows approximately 5 to 8% of the circulating fluid to flow through the bearing section to cool and lubricate the bearing assembly. On the basis of planned bit hydraulics, the type of flow restrictor used is preselected and set in the motor shop; it cannot be changed at the rig site. The drive shaft transmits both axial load and torque to the bit. The drive shaft is a forged component designed such that fatigue, axial, and torque strengths are maximized. It has a threaded connection at the bottom to facilitate connection to the drill bit.

Power delivered to the bit

Eqs 2 and 3 are used to calculate the horsepower delivered to the bit from the motor. Note T (torque) is in the unit of lbf-ft (not lbf/ft).

....................(2)

or, more simply, ....................(3)

in which h_p = horsepower

T= torque in lb-ft

N = speed of rotation in rev/min.

PDM applications in directional drilling

Sidetrack

The most common method of sidetracking out of casing, especially when considerable drilling is to follow, is milling a length of casing with a section mill, then diverting the trajectory with a bent-housing motor assembly. The assembly usually contains a stabilizer on the motor and possibly another one above the motor.

Steerable drilling and kickoff

The essential requirement for a steerable drilling system is that it be capable of making both inclination and azimuth changes. Thus, this is the most commonly used configuration because:

• An average planned curvature can be adhered to by a combination of orienting and rotating.
• After completing the buildup, the assembly can be rotated ahead to hold the angle with minor corrections to inclination and azimuth as necessary.
• Extended intervals can be drilled through different formations without tripping for assembly changes.
• Drilling performance is maximized by efficiently delivering the torque and horsepower at the bit.

This system usually consists of a bent-housing motor and a stabilizer on the bearing housing. To enhance the motor’s sliding capability, the stabilizer has wide, straight blades that are tapered at either end and is undergauge relative to the hole size (typically ⅛ to ½ in.). Depending on the application, additional stabilizers may be used above the motor. Although these stabilizers are generally spiral, the blades should be tapered and undergauge.

The overall design of this steerable assembly will depend on its application. The important considerations are as follows:

1. The expected build rate in oriented mode should be slightly greater than (typically 1 to 2°/100 ft) that required to guarantee the planned build rate.
2. The number of stabilizers used should be kept to a minimum to reduce drag in the oriented mode.
3. If the drillstring is rotated in a curved section, bending stresses around the bent housing should be checked to ensure that they are less than the endurance limit.

Medium-radius applications (6 to 15°/100 ft DLS)

The vast majority of medium-radius drilling is undertaken in hole sizes of 12¼ in. and less with 8-in. (and less) -diameter motors for build rates of 6 to 15°/100 ft. There are a number of motor configurations used to drill medium-radius wells, each with its own merits—single bent-housing motor, single bent housing with offset pad, double-bend motor, bent-housing motor with bent sub positioned on top of the motor and aligned with the bend, and double bent-housing motor.

Intermediate- and short-radius applications

Intermediate-radius drilling systems are used to achieve build rates from 15 to 65°/100 ft. The build and lateral sections are drilled with a short-bearing pack motor. When the build rate exceeds 45°/100 ft, an articulated motor and flexed measurement while drilling (MWD} tool should be used. Both system types can be used for new or re-entry wells.

Two types of motors are used to drill the short-radius wells with build rates ranging from 65 to 125°/100 ft: a “build” articulated motor used to drill the build section and a “hybrid lateral” motor for the horizontal lateral section. The articulated MWD tool is used on both the build and lateral sections.

Rotary steerable systems (RSS)

The RSS is an evolution in directional-drilling technology that overcomes the drawbacks in steerable motors and in conventional rotary assemblies. To initiate a change in the wellbore trajectory with steerable motors, the drilling rotation is halted in such a position that the bend in the motor points in the direction of the new trajectory. This mode, known as the sliding mode, typically creates higher frictional forces on the drillstring. In extreme extended reach drilling (ERD), the frictional force builds to the point at which no axial weight is available to overcome the drag of the drillstring against the wellbore, and, thus, further drilling is not possible. To overcome this limitation in steerable motor assemblies, the RSS was developed in the early 1990s to respond to this need from ERD. The first RSS was used in BP plc’s Wytch Farm (U.K.) extended-reach wells.

RSSs allow continuous rotation of the drillstring while steering the bit. Thus, they have better penetration rate, in general, than the conventional steerable motor assemblies. Other benefits include better hole cleaning, lower torque and drag, and better hole quality. RSSs are much more complex mechanically and electronically and are, therefore, more expensive to run compared to conventional steerable motor systems. This economic penalty tends to limit their use to highly demanding extended-reach wells or the very complex profiles associated with designer wells. Additionally, the technology is still very new. As a result, the current generation of systems (2002) is climbing a very steep learning curve in regard to run length, performance, and mechanical reliability.

There are two steering concepts in the RSS—point the bit and push the bit. The point-the-bit system uses the same principle employed in the bent-housing motor systems. In RSSs, the bent housing is contained inside the collar, so it can be oriented to the desired direction during drillstring rotation. Point-the-bit systems claim to allow the use of a long-gauge bit to reduce hole spiraling and drill a straighter wellbore. The push-the-bit system uses the principle of applying side force to the bit, pushing it against the borehole wall to achieve the desired trajectory. The force can be hydraulic pressure or in the form of mechanical forces. In general, either a point-the-bit or a push-the-bit RSS allows the operator to expect a maximum build rate of approximately 6 to 8°/100 ft for the 8½-in.-hole-sized tool.

Adjustable-gauge stabilizers (AGSs)

In the late 1980s, the industry developed AGSs, the effective blade outer diameter (OD) of which could be changed while the tool was downhole. With AGSs, the drillers could change the stabilizer OD without making time-consuming and costly trips out of the hole. AGSs run in rotary assemblies were often placed near the bit or positioned approximately 15 to 30 ft from the bit. In these positions, changes in their gauge could effectively control the build or drop tendency of the assembly. Because they could control inclination while in the rotary mode, these assemblies became known as “2D rotary systems.” AGSs can also be run with steerable motor systems. Running AGSs with the steerable motor assemblies makes it possible to control inclination with the stabilizer while drilling in the rotary mode. If the wellbore requires a change in azimuth, one would have to revert to a sliding mode.

AGSs have been widely used recently, particularly in drilling the horizontal section with a geological steering or pay-zone steering device that usually consists of a logging while drilling (LWD) tool. With its deep investigation depth, a resistivity sensor can detect a geological change many feet before the bit penetrates that boundary. This ability may allow the drilling assembly to be held in the reservoir and steered away from either an upper or lower boundary.

Whipstocks

Openhole whipstocks are the first type of deflection tool used to change the wellbore trajectory but are seldom used today. Bent-housing motors have replaced openhole whipstocks as the most commonly used deviation tool in openhole sidetracking. Casing whipstocks, on the other hand, are routinely used to sidetrack out of cased wellbores. Whipstocks can be either retrievable or nonretrievable. Retrievable ones are ideal for drilling multiple laterals from a single wellbore. A typical casing-sidetracking operation involves multiple trips to:

• Set the cement plug and the whipstock
• Start the window mill
• Complete the mill
• Clean up

To save time, recently developed systems can accomplish all these tasks in one trip. Note that the gyro survey is usually required for setting the whipstock and for initial tool orientations.

Turbines

Turbines, commonly known as turbodrills, are powered by a turbine motor, which has a series of rotors/stators (stages) connected to a shaft. As the drilling fluid is pumped through the turbine, the stators deflect the fluid against the rotors, forcing the rotors to rotate the drive shaft to which they are connected. Turbines are designed to run on high speed and low torque; thus, they are suited for running with diamond or polycrystalline-diamond compact bits. Turbines are not only less flexible and efficient than PDMs but are also more expensive, so they are not as widely used, except in Russia.

Jetting bits

Jetting bits can be used to change the trajectory of a borehole, with the hydraulic energy of the drilling fluid used to erode a pocket out of the bottom of the borehole. The tricone bit with one large nozzle is oriented to the desired hole direction to create a pocket. The drilling assembly is forced into the jetted pocket for a short distance. This procedure continues until the desired trajectory change is achieved. Jetting is seldom used today because of its slow penetration rate and its limitations in soft formations.

Nomenclature

hp	= horsepower
L1	= distance from the first contact point to the second, ft
L2	= distance from the second contact point to the third, ft
N	= speed of rotation, rev/min
rb	= build rate, ft
T	= torque, lbf-ft
θ	= bend angle, degrees

See also

Directional drilling

PEH:Directional_Drilling