Downhole MotorsDownhole motors have played an integral role in the advancement of

directional drilling technology. The flexibility and control that they provide is far

beyond that attainable with other wellbore deflection techniques, and their

use has become prevalent in an ever-widening range of applications, including

slim hole and coiled tubing operations.

Downhole motors are designed to turn the bit without rotating the drill string.

Thus, it's possible to orient the bit in a desired direction, and maintain its

direction. Moreover, drilling in this "oriented" mode reduces the rig's power

requirements and reduces wear on both surface equipment and tubulars.

Downhole motors come in two basic types: positive displacement motors

(PDMs) and turbine motors.

Downhole Motors

All the PDMs presently in commercial use are of Moineau type, which

uses a stator made of an elastomer. The rotor is make of rigid material

such as steel and is fabricated in a helical shape.

As the rotor rotates, the fluid is passes from chamber to chamber.

These chambers are separate entities and as one opens up to accept

fluid from the preceding, the preceding closes up.

This is the concept of the PDM.

Downhole MotorsThe heart of the positive displacement motor is the rotor-stator assembly,

consisting of a helicoidal rotor that moves within a molded, elastomer-lined

stator.

When circulating fluid is forced through this assembly, it imparts torque to the

rotor, causing it to turn eccentrically. A universal connection transfers this

rotation through a bearing and drive-shaft assembly to a rotating bit sub, which

turns the bit.

Downhole MotorsThe positive displacement motor is easily

the most versatile tool for building or

maintaining hole angle, or for minimizing

crooked hole tendencies. It can be run

with a bent sub or eccentric stabilizer to

initiate deflection.

For maximum directional control with a

minimum of trip time, we may use a

motor with a bent housing.

Downhole Motors

(1) Dump valve: allow the fluid

circulation when the pressure

below a certain threshold.

(2) Multistage power section

(3) Surface-adjustable bent housing

(4) Thrust and radial-bearing

section

Downhole Motors

The main advantages of the PDM:

• Used to drill with soft, medium and hard rock formations.

• Used with any type of rock bits.

• Most surface pump systems can be used.

• Normal surface pump systems can be used to operate these downhole motors.

• Can be operated with aerated muds, foam and air mist.

The main disadvantages of the PDM:

• The elastomer of the stator can be damaged by high temperatures and some

hydrocarbons.

Downhole MotorsTurbine Motors

Downhole Motors

The rotational energy provided by the flowing fluid is used to rotate and

provide torque to the drill bit.

The DTM is composed of two sections: (1) the turbine motor section and

(2) the thrust-bearing and radial support bearing.

The turbine section has multistages of rotors and stators: 25 – 300.

For a given flowrate, increasing number of stages causes an increase in

torque.

Downhole Motors

Downhole MotorsThe drilling fluid after passing through the turbine motor section is channeled

into the center of the shaft through large openings in the main shaft.

The drill bit is attached to the lower end of the main shaft.

The weight on the bit is transferred to the downhole turbine motor housing

via the thrust-bearing section. This bearing section provides for rotation while

transferring the weight on the bit to the downhole turbine motor housing.

In the thrust-bearing section is a radial support bearing section that provides a

radial load-carrying group of bearings that ensures that the main shaft rotates

about center even when a side force on the bit is present during drilling

operations.

Downhole Motor

The main advantages:

• Hard or extremely hard competent rock formations can be drilled

with turbine motors using diamond or the PDC bits.

• High ROP can be achieved since bit rotation speed is high.

• Allow circulation of the borehole regardless of motor horsepower or

torque being produced by the motor.

Downhole Motors

The main disadvantages:

• Bit speeds are high, which limits the use of roller rock bits.

• Significantly larger pump system is required.

• Unless a MWD instrument is used, there is no way to ascertain

whether the turbine motor is operating efficiently since rotation,

speed, and torque cannot be measured using normal surface data.

• Long power section to obtain the needed power to drill.

Downhole MotorsTurbine motors operate at relatively high rotary speeds, and so are run

exclusively with fixed cutter (PDC or natural diamond) bits. Turbine motor

may allow for higher bit weight and a smoother hole for logging and

casing operations than a PDM

Downhole Motors

If there is no resisting torque at the drive shaft (no weight on bit), drilling

fluid passes freely through the rotor and the turbine runs with high rotary

speed, which is called runaway speed (Nra).

As the loading on the drillbit is increased (as WOB is added, torque is

increased) the rotational speed is decreased and eventually the motor stalls

(N=0 rpm).

At constant flow rate, the motor torque varies linearly with bit RPM. At stall

conditions the turbodrill develops maximum torque, Tmax.

Downhole MotorsTurbine motors have narrower operating ranges than positive

displacement motors. The relatively small diameter of the turbines

and resulting higher rotational speeds translate into greater fluid flow

requirements.

They also tend to be longer than PDMs, which limits their ability to

make high-angle directional changes.

Because of these limitations, which are inherent in the turbine motor

design, positive displacement motors are used much more

commonly.

Deviation

Rotary steerable systems (RSS) represent a relatively new form of directional

drilling technology in which specialized downhole equipment replaces conventional

directional tools such as mud motors.

They are generally programmed by the MWD engineer or directional driller, who

transmits commands from the surface by means of fluid pressure fluctuations in

the mud column or variations in the drill string rotation .

The tool receives these commands and gradually steers in the desired direction.

Thus, unlike a mud motor, which works in a "sliding" mode (i.e., without drill string

rotation), the RSS is designed to drill directionally with continuous rotation from

the surface

Deviation

Deviation

The advantages of this technology are many for geoscientists & drillers

1. The flow of drilled cuttings past the BHA is enhanced. This results in improved transport

of drilled cuttings to the surface.

2. Continuous rotation help to reduces drag and risk of sticking.

3. Continuous rotation improves ROP

4. Continuous rotation also provides better weight transfer.

5. Continuous rotation helps borehole walls smoother than those drilled with mud motors;

and hence provides higher quality measurements of formation properties.

DeviationRotary steerable systems are of two types

- push-the-bit systems and point-the-bit

systems.

Push-the-bit systems steer the bit by

applying a side load that forces the bit

laterally in the direction of the desired

curve.

Point-the-bit systems steer the bit by

tilting the bit in the direction of the

desired curve.Push the bit Point the bit

DeviationA pure push the bit RSS achieves the trajectory change by applying a side

load to the bit by non-rotating (stationary) pads or stabilizers that are

pushed against the wall of the hole. Since the pads can be pushed out

only a certain distance they become ineffective in borehole sections that

easily develop washouts.

DeviationPoint the Bit

Deviation

A point the bit RSS is furnished with a steering assembly that controls

the direction of drilling (inclination and azimuth) by orienting the tilted

shaft to which a drill bit is attached.

The bit is deflected internally with a hydraulic system, allowing the drill

bit to be offset and pointed out in the desired direction.

The disadvantage of a “point the bit” system is that they are slower to

react to required well path changes and achievable dogleg severity is

less than that of a “push the bit” system.

DeviationRotary steerable systems allow

operators to plan complex wellbore

geometries, including horizontal and

extended-reach wells, which could not

be drilled efficiently or effectively with

conventional drilling methods.

RSS accomplish this by enabling full

directional drilling control in three

dimensions.

Deviations

In fields with well-defined drilling tendencies and formation

characteristics, it is often possible to maintain reasonable

control over the borehole trajectory without resorting to

specialized directional drilling tools. This is done by

configuring drill collars, stabilizers, reamers and other BHA

components to build or drop hole angle as needed.

Bottom Hole Assembles

Deviations

Dropping

Deviations

Building

Deviations

Holding

Deviations

Deviations

DeviationAs the distance between the first and second stabilizer is increased the drill collar

deflection (sag) will also increase, thereby increasing the bit side force (BSF). If the

second stabilizer is placed too far from the first, drill collars may contact the wellbore

between the stabilizers and the building tendency may be lost.

For a given bending stiffness, weight of drill collars, and the radial clearances at

stabilizers and drill collars, the sag of drill collars depends on hole inclination angle and

weight on bit.

Generally, it is not recommended to place the second stabilizer more than 60 ft from

the first one. In some applications, four, or even more, stabilizers are closely spaced to

increase the overall stiffness of BHA and thereby drill a straight hole with constant

inclination angle.

DeviationIn theory, only one stabilizer is needed to develop the pendulum effect that

tends to decrease the hole inclination angle, but often three stabilizers are

used.

For given drilling conditions (formation and drillbit type,WOB, etc.), the drop

rate is a strong function of the distance between the bit and the first

stabilizer. As the distance to the first stabilizer is increased the lateral

component of the weight of drill collars is also increased and the bit is

pushed to the low side of the hole.

Generally, the distance between the bit and first stabilizer is approximately

30ft. Of course, the radial clearances between wellbore wall and

stabilizers/drill collars must also be carefully selected.

Deviation

Although mud motors and rotary steerable systems are

overwhelmingly the tools of choice for controlled directional

drilling, there are other tools that may be of some use in

certain areas. These include:

1. Directional wedges (Whipstocks)

2. Jet bits with oriented nozzles

Deviation

Deviation

The wedge is attached to the bottomhole assembly by means of a shear pin.

The assembly is lowered to bottom and oriented in the proper direction.

The driller applies weight to set the wedge and shear the pin, drills 10 to 15 feet of

undergauge hole, then trips the tools so a full-gauge hole opener can be run.

After drilling the section, a survey is made to assure proper direction, and the

process is repeated until the build section of the well is completed.

The directional wedge technique is time-consuming, has limited applications, and

requires a high degree of technical expertise to properly implement. For these

reasons, it is seldom used.

Deviation

Deviation

Jetting bits with orienting nozzles can be effective at initiating deflection in

very soft formations.

The bit is lowered to bottom , the jet is oriented in the desired direction,

and mud flow is initiated with no drill string rotation.

After hydraulically gouging a small pilot hole (about 3 feet), the driller

initiates conventional rotary drilling to open the section to full gauge. The

process is then repeated.

Hole surveys are made after drilling 10 to 15 feet of build section.