Downhole Mud Motors

There are two major types of downhole motors powered by mud flow;

1) The turbine, which is basically a centrifugal or axial pump and

2) The positive displacement mud motor (PDM). The principles of operation are shown in Figure  and the design of the tool are totally different.
Turbines were in wide use a number of years ago and are seeing some increased use lately but the PDM is the main workhorse for directional drilling.


  • Motor Selection

Four configurations of drilling motors provide the broad range of bit speeds and torque outputs required satisfying a multitude of drilling applications. These configurations include:

High Speed / Low Torque

Medium Speed / Medium Torque

Low Speed / High Torque

Low Speed / High Torque -Gear Reduced

The high speed drilling motor utilizes a 1:2 lobe power section to produce high speeds and low torque outputs. They are popular choices when drilling with a diamond bit, tri-cone bit drilling in soft formations and directional applications where single shot orientations are being used.

The medium speed drilling motor typically utilizes a 4:5 lobe power section to produce medium speeds and medium torque outputs. They are commonly used in most conventional directional and horizontal wells, in diamond bit and coring applications, as well as sidetracking.

The low speed drilling motor typically utilizes a 7:8 lobe power section to produce low speeds and high torque outputs. They are used in directional and horizontal wells, medium to hard formation drilling, and PDC bit drilling applications.

The gear reduced drilling motor combines a patented gear reduction system with a 1:2 lobe high speed power section. This system reduces the output speed of the 1:2 lobe power section by a factor of three, and increases the output torque by a factor of three. The result is a drilling motor with similar performance outputs as a low speed drilling motor, but with some significant benefits. The 1:2 lobe power section is more efficient at converting hydraulic power to mechanical power than a multi-lobe power section and also maintains more consistent bit speed as weight on bit is applied. This motor can be used in directional and horizontal wells, hard formation drilling, and PDC bit drilling applications.

Some other motor selections are also available including a tandem and modified motor. These variations are described below.

Tandem Drilling Motor - The drilling motor utilizes two linked power sections for increased torque capacity.

Modified Drilling Motor - The bearing section of the drilling motor has been modified to provide different drilling characteristics (ie. change bit to bend distance, etc.).

  • Components

All drilling motors consist of five major assemblies:

  1. Dump Sub Assembly
  2. Power Section     
  3. Drive Assembly
  4. Adjustable Assembly
  5. Sealed or Mud Lubricated Bearing Section.

The gear reduced drilling motor contains an additional section, the gear reducer assembly located within the sealed bearing section. Some other motor manufacturers have bearing sections that are lubricated by the drilling fluid.

  • Dump Sub Assembly
As a result of the power section (described below), the drilling motor will seal off the drill string ID from the annulus. In order to prevent wet trips and pressure problems, a dump sub assembly is utilized. The dump sub assembly is a hydraulically actuated valve located at the top of the drilling motor that allows the drill string to fill when running in hole, and drain when tripping out of hole. When the pumps are engaged, the valve automatically closes and directs all drilling fluid flow through the motor.
In the event that the dump sub assembly is not required, such as in underbalanced drilling using nitrogen gas or air, it’s effect can be negated by simply replacing the discharge plugs with blank plugs. This allows the motor to be adjusted as necessary, even in the field. Drilling motors 95 mm (3 3/4”) and smaller require the dump sub assembly to be replaced with a special blank sub.
  • Power Section
The drilling motor power section is an adaptation of the Moineau type positive displacement hydraulic pump in a reversed application. It essentially converts hydraulic power from the drilling fluid into mechanical power to drive the bit.
The power section is comprised of two components; the stator and the rotor. The stator consists of a steel tube that contains a bonded elastomer insert with a lobed, helical pattern bore through the centre. The rotor is a lobed, helical steel rod. When the rotor is installed into the stator, the combination of the helical shapes and lobes form sealed cavities between the two components. When drilling fluid is forced through the power section, the pressure drop across the cavities will cause the rotor to turn inside the stator. This is how the drilling motor is powered.
It is the pattern of the lobes and the length of the helix that dictate what output characteristics will be developed by the power section. By the nature of the design, the stator always has one more lobe than the rotor. The illustrations in Figure  show a 1:2 lobe cross-section, a 4:5 lobe cross-section and a 7:8 lobe cross-section. Generally, as the lobe ratio is increased, the speed of rotation is decreased.
The second control on power section output characteristics is length. A stage is defined as a full helical rotation of the lobed stator. Therefore, power sections may be classified in stages. A four stage power section contains one more full rotation to the stator elastomer, when compared to a three stage. With more stages, the power section is capable of greater overall pressure differential, which in turn provides more torque to the rotor.
As mentioned above, these two design characteristics can be used to control the output characteristics of any size power section. This allows for the modular design of drilling motors making it possible to simply replace power sections when different output characteristics are required.
In addition, the variation of dimensions and materials will allow for specialized drilling conditions. With increased temperatures, or certain drilling fluids, the stator elastomer will expand and form a tighter seal onto the rotor and create more of an interference fit, which may result in stator elastomer damage. Special stator materials or interference fit can be requested for these conditions.
  • Drive Assembly
Due to the design nature of the power section, there is an eccentric rotation of the rotor inside of the stator. To compensate for this eccentric motion and convert it to a purely concentric rotation drilling motors utilize a high strength jointed drive assembly. The drive assembly consists of a drive shaft with a sealed and lubricated drive joint located at each end. The drive joints are designed to withstand the high torque values delivered by the power section while creating minimal stress through the drive assembly components for extended life and increased reliability. The drive assembly also provides a point in the drive line that will compensate for the bend in the drilling motor required for directional control.
  • Adjustable Assembly
Most drilling motors today are supplied with a surface adjustable assembly. The adjustable assembly can be set from zero to three degrees in varying increments in the field. This durable design results in wide range of potential build rates used in directional, horizontal and re-entry wells. Also, to minimize the wear to the adjustable components, wear pads are normally located directly above and below the adjustable bend.
  • Sealed or Mud Lubricated Bearing Section
The bearing section contains the radial and thrust bearings and bushings. They transmit the axial and radial loads from the bit to the drill string while providing a drive line that allows the power section to rotate the bit. The bearing section may utilize sealed, oil filled, and pressure compensated or mud lubricated assemblies. With a sealed assembly the bearings are not subjected to drilling fluid and should provide extended, reliable operation with minimal wear. As no drilling fluid is used to lubricate the drilling motor bearings, all fluid can be directed to the bit for maximized hydraulic efficiency. This provides for improved bottom-hole cleaning, resulting in increased penetration rates and longer bit life. The mud lubricated designs typically use tungsten carbide-coated sleeves to provide the radial support. Usually 4% to 10% of the drilling fluid is diverted pass this assembly to cool and lubricate the shaft, radial and thrust bearings. The fluid then exits to the annulus directly above the bit/drive sub.
  • Gear Reducer Assembly
An alternative to the type low speed drilling motor is the gear reduced design. It utilizes a gear reduction assembly within the sealed bearing section in combination with a 1:2 lobe power section. This patented design reduces the speed of rotation by a factor of three while increasing the torque by the same multiple. The benefit with this design is increased stability in the bit speed for different differential pressures, and improved hydraulic efficiency out of the power section.
  • Kick Pads
Most drilling motors can incorporate wear pads directly above and below the adjustable bend for improved wear resistance. Eccentric kick pads can also be used on most motors ranging from 121 mm (4 3/4’) to 245 mm (9 5/8”) in size. This kick pad is adjustable to match the low side of the motor to increase build rate capabilities. It will also allow lower adjustable settings for similar build rates, thereby reducing radial stresses applied to the bearing assembly, and permit safer rotation of the motor. They can be installed in the field by screwing them onto specially adapted bearing housings.
  • Stabilization
Bearing housings are also available with two stabilization styles, integral blade and screw-on. The integral blade style is built directly onto the bearing housing and thus cannot be removed in the field. The screw-on style provides the option of installing a threaded stabilizer sleeve onto the drilling motor on the rig floor in a matter of minutes. The drilling motor has a thread on the bottom end that is covered with a thread protector sleeve when not required. Both of these styles are optional to a standard bladed bearing housing.
  • Drilling Motor Operation

In order to get the best performance and optimum life of drilling motors, the following standard procedures should be followed during operation. Slight variations may be required with changes in drilling conditions and drilling equipment, but attempts should be made to follow these procedures as closely as possible.

  • Assembly Procedure & Surface Check Prior to Running in Hole

Most motors are shipped from the shop thoroughly inspected and tested, but some initial checks should be completed prior to running in hole. These surface check procedures should only be used with mud drilling systems. To avoid potential bit, motor, and BOP damage, these preliminary checks should be completed without a bit attached. A thread protector should be installed in the bit box whenever moving the motor, but must be removed before flow testing.

  1. The correct lift sub must always be installed and used for moving the tool on or off the rig floor, and for lifting the tool into position for make-up. Also be sure the connection between the lift sub and the drilling motor is tight. To lift the drilling motor to the rig floor, use a tugger line secured around the lift sub. Pick up the drilling motor with the elevators and set it into the slips of the rotary table. Install the dog collar/safety clamps. The lift sub supplied with the drilling motor should only be used for lifting the drilling motor. The capacity of the lift sub is restricted to the weight of the drilling motor and should not be used for any other purpose. Only apply rig tongs on the identified areas of the drilling motor. All connections marked “NO TONGS” of the drilling motor are torqued in the service shop. Further make-up on the rig floor is not necessary, and if attempted may cause damage.
  2. Remove the lift sub and connect the kelly to the drilling motor, remove the safety clamp, and lift the drilling motor out of the slips. Remove the thread protector from the bit box and inspect the threads for damage.
  3. Lower the drilling motor until the dump sub ports are below the rotary table, yet still visible. CAUTION: The dump sub valve will remain open until there is enough fluid pressure to close it. Therefore, the drilling motor should be lowered until the ports are below the rotary table. This will prevent the initial flow of drilling fluid from spraying on the rig floor.
  4. Slowly start the pumps and ensure drilling fluid is flowing out of the dump sub ports. Increase the flow rate until the dump sub ports close, and drilling fluid stops flowing out. Make note of the circulation rate and standpipe pressure. CAUTION: Do not exceed the maximum recommended flow rate for this test.
  5. Lift the drilling motor until the bit box becomes visible. It should be rotating at a slow, constant speed. Listen to the bearing section of the drilling motor for excessive bearing noise, especially if the tool has been used previously without being serviced.
  6. Before stopping the pumps, the drilling motor should be lowered below the rotary table. Ensure that drilling fluid flows out of the dump sub ports after shutting down the pumps. It is possible that the dump sub valve remains closed after this test due to a pressure lock. If this occurs, no drilling fluid will flow out of the ports. To remove the pressure lock, bleed off some stand pipe pressure and the valve will open. The surface check should be as short as possible; since it is merely to ensure that the drilling motor is rotating.
  7. After this surface check, the bit should be attached to the motor using a bit-breaker, while holding the bit box stationary with a rotary tong. Be sure to avoid contacting the end cap directly above the bit box with the tong dies. It is recommended that you never hold the bit box stationary and rotate the drilling motor counter-clockwise, or hold the drilling motor stationary and rotate the bit box clockwise. This could possibly cause the internal drilling motor connections to back off and damage it. Although rotating in the opposite direction will result in drilling fluid to be pushed out the top end, the internal connections will not be at risk of disconnecting. Get wet or damage motor.
  8. If the drilling motor has been used previously, an overall inspection should be completed. Inspect for seal integrity by cleaning the area above the bit box and visually checking for lubricating oil leakage or seal extrusion. General visual inspection of the entire drilling motor should be carried out to check for missing oil plugs, housing damage, or loose connections.
  9. Set the adjustable assembly to the desired bend. The instructions for this procedure depend upon the motor manufacturer and should be adhered to. Ensure the rig tongs can generate the required make-up torque the motor.
  10. If a float sub is used, it should be placed immediately above the drilling motor.
  • Tripping In Hole

Generally, a drill string with a drilling motor can be run into the hole like a standard bottom hole assembly. The drilling motor is rugged, but care should be taken to control travel speed while tripping into the hole. The drill string should be tripped with the blocks unlocked and special care must be taken when passing the B.O.P., casing shoe, liner hanger, bridges and nearing bottom. Tight spots should be traversed by starting the pumps and slowly reaming the drilling motor through. When reaming, the drill string should be periodically rotated to prevent sidetracking. Great care should be taken during these operations.

When tripping to extreme depths, or when hole temperatures are high, periodic stops are recommended to break circulation. This prevents bit plugging and aids in cooling the drilling motor, preventing high temperature damage.

Fluid should not be circulated through a drilling motor inside casing if a PDC or diamond bit is being used, as this may damage the bit cutters.

If a dump sub assembly is not used and the pipe is not being filled while tripping in, the back pressure on the power section will cause the rotor to turn in reverse. This could cause internal connections of the drilling motor to unscrew. Stop and break circulation before putting drilling motor on-bottom. Failure to do so could plug jets and/or damage the drilling motor.

  • Drilling

After the assembly has been tripped to the bottom of the hole, drilling motors should be operated in the following manner:

  1. With the bit 1-2 meters (3-6 feet) off bottom, start the pumps and slowly increase the flow rate to that desired for drilling. Do not exceed the maximum rated flow rate for the drilling motor.
  2. Make a note of the flow rate and the total pump pressure. Note that the pressure may exceed the calculated off bottom pressure due to some side load effects between the bit and the hole diameter.
  3. After a short cleaning interval, lower the bit carefully to bottom and slowly increase the weight. Torque can be affected by a dirty, uncirculated hole and the hole should be adequately cleaned prior to orienting the tool. Fill maybe cleaned out of the wellbore by slowly rotating the drilling motor or by staging the drilling motor full circle 30o to 45o at a time. This prevents ledge buildup and side tracking.
  4. Orient the drill string as desired and slowly apply further weight onto the bit. Pump pressure will rise as the weight on bit is increased. Record the change in system pressure between the off bottom and on bottom values. This will be the differential pressure. Try to drill with steady pump pressure by keeping a steady flow rate and constant weight on bit.
  5. Adding weight on bit will cause both the differential pressure and torque to increase. Similarly, reducing weight on bit will reduce both the differential pressure and the torque. Therefore, the rig pressure gauge enables the operator to monitor how the drilling motor is performing, as well as a weight on bit indicator.
  6. Applying excessive weight on bit may cause damage to the on-bottom thrust bearings. Similarly, applying excessive tension while stuck may cause damage to the off-bottom thrust bearings. Refer to the manufacturer specifications for the recommended maximum loads for these conditions.
  7. Optimum differential pressure can be determined by monitoring motor performance, penetration rate, and drilling requirements. Also, maintaining a constant weight on bit and differential pressure assists in controlling orientation of the drill string.
  • Reactive Torque
Drilling motors drive the bit with a right-hand (clockwise) rotation. As weight is added to the bit, reactive torque acting on the drilling motor housing is developed. This left-hand (counter-clockwise) torque is transferred to the drill string and may cause the joints above the motor to tighten. Reactions of this type increase with larger weight on bit values and reach a maximum when the motor stalls. This reactive torque also affects the orientation of the motor when it is used in directional drilling applications. Therefore, this reactive torque must be taken into account when orienting the drilling motor from the surface in the desired direction. As a rule-of-thumb 4 ½” drill pipe will turn 10o
for every 300m (1,000’).
Determining the amount of torque generated by the motor and using drill pipe twist tables can also produce a rough determination of the torsional angle of the drill string. By measuring the on-bottom and off-bottom pressure, the differential pressure can be determined. With this value use the torque performance charts for the motor to determine the approximate downhole torque generated. Utilizing the following drill string twist table will estimate the amount of reactive torque.
  • Critical Rotary Speed

Motor sections are available in a number of configurations. These different designs are identified by the number of lobes on the rotor and cavities in the stator. For example a 4/5 power section has 4 lobes and 5 cavities. With every rotation made by the rotor, there are eccentric motions about the radius of the rotor equal to the number of lobes. So a 4/5 power section would go through 4 eccentric movements for every rotation. In all multi-lobed tools, regardless of size or configuration, the critical tolerance for this eccentric movement is 1000 cycles per minute. Exceeding this critical tolerance sets up three degenerative cycles in the tool:

  • The high oscillation factor combined with the inherent friction of the rotor contacting the stator results in excessive heat generation in the stator molding. Oscillations above 1000 cycles per minute may result in temperatures sufficient to cause hysteretic failure of the stator molding (elastomer doesn’t return to original shape).
  • Vibration frequencies are introduced by the high oscillation rates that can contribute to mechanical failures in motor components other than the rotor and stator. It is not known if these vibrations are harmonic or random however, it is logical to assume that some degree of resonance would be present in the frequency.
  • The centrifugal force of the rotor in an “over-speed” condition combined with the diminished compressive strength of a stator in hysteretic failure, accentuate the eccentric motion (run out) of the rotor. The result is an expontenial increase in the degenerative effects of the condition.
  • Drilling Motor Stall

Stalling usually occurs when the application of excessive weight on bit or hole sloughing stops the bit from rotating and the power section of the drilling motor is not capable of providing enough torque to power through. This is indicated by a sudden sharp increase in pump pressure. This pressure increase is developed because the rotor is no longer able to rotate inside the stator, forming a long seal between the two. If circulation is continued, the drilling fluid forces it’s way through the power section by deflecting the stator rubber. Drilling fluid will still circulate through the motor, but the bit will not turn. Operating in this state will erode and possibly chunk the stator in a very short period of time, resulting in extensive damage. It is very important to avoid this operating condition.

When stalling occurs, corrective action must be taken immediately. Any rotary application should be stopped and built up drill string torque released. Then the weight on bit can be reduced allowing the drill bit to come loose and the drilling motor to turn freely. If the pump pressure is still high, the pumps should then be turned off. Once again, failure to do this will result in the stator eroding until the drilling motor is inoperable.

Other conditions can be occurring downhole that indicate the motor is stalling. On underbalanced wells when the motor is being supplied with too low a combined equivalent flow rate will not drill (see later discussion on two-phase flow tests). Under gauge bits or a badly worn heel row of cutters on the bit can also make the motor stall.

  • Bit Conditions

The bit speeds developed when drilling with a drilling motor are normally higher than in conventional rotary drilling. This application tends to accelerate bit wear. When drilling with a drilling motor and simultaneously rotating the drill string, it is important to avoid locking up the bit and over running the drilling motor with the rotary table. A locked bit will impart a sudden torque increase in the drilling motor which can be detected by a sudden, sharp increase in standpipe pressure. Small pressure fluctuations can also indicate the onset of bit failure.

  • Rotating the Drilling Motor

For directional control, we often rotate a drilling motor which has the adjustable assembly set for a deviation angle. It has been found that rotating the drilling motor set at bends greater than 1.8 degrees may fatigue the housings of the drilling motor to a point where a fatigue crack is initiated, and fracture occurs. Additionally, rotation of motors with settings greater than 1.83 degrees place high radial stresses on the bearing section which may initiate premature failure. Most motor manufacturers have a policy that drilling motors set at greater than 1.83 degrees not be rotated. The extent of the damage is very dependent upon the drilling conditions and formations being drilled. Although fractures from fatigue due to rotating over 1.83 degrees are a relatively rare occurrence, a risk is still being taken when it is done. The operator of the drilling motor must be aware of this risk.

It is also recommended that the speed of rotation not exceed 50 RPM. If this value is exceeded, excessive cyclic loads would occur to the drilling motor housings and possibly causing pre-mature fatigue problems.

  • Tripping Out

Prior to tripping out when drilling with conventional mud, it is recommended that the fluid be circulated for at least one “bottoms-up’ time to ensure that the wellbore has been cleaned thoroughly.

The tripping out procedures for a drilling motor is basically the same as those for tripping in. Taking care when pulling the drilling motor through tight spots, liner hangers, casing, casing shoes, and the B.O.P. is necessary to minimize possible damage to both the drilling motor and the wellhead components. Rotating may also be done to assist with the removal of the drill string. The dump sub valve will allow the drill string to be emptied automatically when tripping.

Although the drill string will drain when tripping out, the drilling motor itself may not. Once the drilling motor is at surface, rotating the bit box in a counter-clockwise direction will naturally drain the drilling motor through the top. This is recommended before laying down the motor since aggressive drilling fluids can deteriorate the elastomer stator and seals. When possibly, fresh water should also be flushed through to ensure thorough cleaning of the drilling motor. Also, clean the bit box area with clean water and install a thread protector into the box connection.

Rotating the bit box in a clockwise direction will naturally drain the drilling motor through the bottom, but one of the internal connections could break and unscrew. For this reason, it is not recommended to rotate it in this manner.


  • Surface Checks After Running in Hole

Before laying down a drilling motor, it should be inspected in the event that it is required again before servicing. Listen for indications of internal damage when draining the drilling motor. Inspect the seal area between the bit box and the bearing section for lubricating oil leakage, and check the entire drilling motor for loose or missing pressure plugs. If there are any concerns with the drilling motor, it should be laid down for servicing.

  • Drilling Fluids
Most drilling motors are designed to operate effectively with practically all types of drilling fluids. In fact, the stator or power-section of most PDM’s are supplied by the same one or two manufacturers with the same general elastomer type. Successful runs have been achieved with fresh or salt water, oil based fluids, fluids with additives for viscosity control or lost circulation, and with nitrogen gas. However, some consideration should be taken when selecting a drilling fluid, as elastomer components of the drilling motor are susceptible to pre-mature wear when exposed to certain fluids especially under higher temperatures.

Hydrocarbon based drilling fluids can be very harmful to elastomers. A measure of this aggressiveness is called the Aniline Point. The Aniline Point is the temperature at which equal amounts of the hydrocarbon and aniline become miscible. This temperature is an indication of the percent of light ends (aromatics) present in the hydrocarbon. It is recommended that the aniline point of any drilling fluid not be lower than 70 to 94.5o C (158 to 200o F), depending upon stator manufacturer. The lower the aniline point the higher the percentage of elastomer damaging “high-ends” in the hydrocarbon fluid. Also, the operating temperature of the drilling fluid should be lower than the aniline point. Operating outside these parameters tends to excessively swell elastomers and cause premature wear, thus reducing the performance of the motor. In cases where hydrocarbon based fluids are used it is recommended that stators material or designs that account for the elastomer swelling be used (HSN or changed interference of stator/rotor.

Drilling fluids with high chloride content can cause significant damage to internal components (chrome plated rotors). When these components become damaged, the drilling motor’s performance is dramatically reduced.

Lost circulation materials can be used safely with drilling motors but care must be taken to add the material slowly to avoid plugging the system. (Good rule of thumb is no more than 2.5 lbs/barrel). If coarse lost circulation material is required a circulating sub should be installed above the motor assembly to by-pass the motor.
The percentage of solids should be kept to a minimum. Large amounts of abrasive solids in the drilling fluid will dramatically increase the wear on a stator. It is recommended that the sand content be kept below 2% for an acceptable operational life. A solids content greater than 5% will shorten rotor and stator life considerably.

For the above reasons, it is extremely important to flush the drilling motor with fresh water before laying it down, especially when working with the types of drilling fluids described above. Failure to do so will allow the drilling fluid to further seriously deteriorate components to the drilling motor long after it has been operated. The solids can also settle out in the motor and in the worse case lock the motor up.

  • Temperature Limits
The temperature limits of drilling motors again depend on the effect of different fluids and temperatures on the components made of elastomers. Generally, standard drilling motors are rated for temperatures up to 105o C (219o F). At temperatures above this, the performance characteristics of elastomers are changed, resulting in reduced life expectancy. When exposed to higher temperatures, the elastomers swell, creating more interference than desired, wearing the parts out prematurely. The strength of the elastomers is also affected. When drilling in wells with temperatures greater than 121o C (250o F) it is important to maintain circulation to minimize the temperature the stator liner is subjected to.

To compensate for these elastomer changes, special materials and special sizes of components are used. This results in drilling motors that are specifically assembled for high temperatures. These special order drilling motors may be operated in temperatures up to 150o C (300o F) and higher. The rubber in the stator is specially selected for more clearance at higher temperatures to minimize interference. Therefore, at lower temperatures, the stator elastomer will not seal adequately on the rotor and fluid bypass will occur. Therefore, it is important that the drilling motor be used in the conditions it is designed for in order to operate as required.

To compensate for these elastomer changes, special materials and special sizes of components are used. This results in drilling motors that are specifically assembled for high temperatures. These special order drilling motors may be operated in temperatures up to 150o C (300o F) and higher. The rubber in the stator is specially selected for more clearance at higher temperatures to minimize interference. Therefore, at lower temperatures, the stator elastomer will not seal adequately on the rotor and fluid bypass will occur. Therefore, it is important that the drilling motor be used in the conditions it is designed for in order to operate as required.
  • Hydraulics

The use of a PDM in the drill string changes the hydraulic calculations and should be considered. Various factors have to be taken into account. These are:

1. Range of flow rates allowable: Each size and type of PDM is designed to take a certain range of volumes of fluid.

2. No-load Pressure Loss: When mud is pumped through a mud motor which is turning freely off-bottom (i.e. doing no work) a certain pressure loss is needed to overcome the rotor/stator friction forces and cause the motor to turn. This pressure loss and motor RPM are proportional to flow rate. Their values are known for each size and type of PDM. The no-load pressure loss is usually no greater than 100 psi.

3. Pressure Drop across the Motor: As the bit touches bottom and effective WOB is applied, pump pressure increases. This increase in pressure is normally called the motor differential pressure. Motor torque increases in direct proportion to the increase in differential pressure. This differential pressure is required to pump a given volume of mud through the motor to perform useful work. For a multi-lobe motor, it can be 500 psi or even more.

4. Stall-out Pressure: There is a maximum recommended value of motor differential pressure. At this point, the optimum torque is produced by the motor. If the effective WOB is increased beyond this point, pump pressure increases further. The pressure across the motor increases to a point where the lining of the stator is deformed. The rotor/stator seal is broken and the mud flows straight through without turning the bit (blow-by or slippage). The pump pressure reading jumps sharply and does not vary as additional WOB is applied. This is known as stall-out condition.

Studies have shown that the power output curve is a parabola and not a smooth upward curve, as originally thought. If the PDM is operated at 50%-60% of the maximum allowable motor differential pressure, the same performance should be achieved as when operating at 90% of differential. The former situation is much better however, there is a much larger ‘cushion’ available before stall-out. This should result in significantly longer motor life.

The greater the wear on the motor bearings, the easier it is to stall-out the motor. It is useful to deliberately stall out the PDM briefly on reaching bottom. It tells the directional driller what the stall-out pressure is. He may want to operate the motor at about 50% of stall-out differential pressure. In any case, he must stay within the PDM design specifications.

It is obvious that, if the pump pressure while drilling normally with a mud motor is close to the rig’s maximum, stalling of the PDM may lead to tripping of the ‘pop-off valve’. This should be taken into account in designing the hydraulics program.

Rotor Nozzle: Most multi-lobe motors have a hollow rotor. This can be blanked off or jetted with a jet nozzle. When the standard performance range for the motor matches the drilling requirements, a blanking plug is normally fitted.

The selection of the rotor nozzle is critical. Excessive bypass will lead to a substantial drop in motor performance and, consequently, drilling efficiency. If a rotor nozzle is used at lower flow rates, the power of the motor will be greatly reduced.

From the above, it is clear that careful planning of the PDM hydraulics program is required.


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