IPS MUD MOTOR HANDBOOK 2017
INTEGRADORA DE PERFORACIONES Y SERVICIOS
IPS Mud Motor Handbook Primera edición en México: noviembre 2016 www.ips-mexico.com
DOWNHOLE MOTOR Positive displacement device based on the principle of Moineau in wich transforms the hydraulic energy of drilling fluid into mechanical energy, transferring torque and rotation to the drilling bit.
Advantages and features: • Low operating cost per hour • Operators can increase desired operating parameters • Supports next generation of power sections • Rotor and bit box catches improve safety • 0° - 3° adjustable bent housings (three pieces simple adjustable) • Dual wear pads with tough hardfacing
IPS motor innovations: • IPS mud motor was developed with the expertise of our Directional Drillers, Engineers and maintenance Personnel. • Short bit to bend section for fast steerable response and higher Build Rates.
Applications: • Performance Drilling • Directional Drilling • Horizontal Drilling/Short Radius • Multilateral wells • Reentry • Underbalance drilling • Rotary Steerable drilling
MOTOR COMPONENTS
1. Top Sub 2. Rotor Catch 3. Power Section 4. Coupling Assembly (Adjustable benthousing / Drive Assembly) 5. Bearing Section
Top Sub: The Top Sub is a Cross Over Sub, to connect the motor to the drill string using an API tool joint box thread and a special pin to connect to motor’s stator.
Rotor Catch: It runs inside the Top Sub and provides the ability to recover or “catch” the motor in case of a backed off connection or if the motor breaks bellow the Top Sub prevent fishing job.
POWER SECTION The power section is basically a Moineau pump operated in reverse when drilling fluid is pumped in to the drill string . When pressure is applied inside, the power section transforms the hydraulic energy from the drilling fluid pressure to mechanical energy transmitting rotation and torque to the drill bit. The power section consists in two parts, the rotor and the stator. The rotor is a steel bar with helical shape covered with chrome to reduce wear and corrosion when it runs inside the stator. The stator is a steel tube lined with a rubber compound called Elastomer. The Stator elastomer liner has the same pattern of the rotor but it has one additional lobe to allow the rotor runs inside the stator. When the power section is assembled, the combination of helical patterns form flow cavities between the stator and the rotor at the points of contact.
Power Section Configuration: The rotor/stator configurations are designated by the ratio of their lobes. The speed and torque depends of the rotor/ stator ratio. The higher number of rotor/stators lobe yields a power section with slower speed and higher torque. Fewer number of rotor/stator lobe yields a power section with higher speed and lower torque.
The IPS mod motor can be configurated in a variety on rotor/Stator lobe configurations and temperature ranges from 70°F to 375°F.
Power Section Elastomer: IPS offers two different types of power section elastomers: High performance Elastomer and high Temperature Elastomer.
Coupling Section (Adjustable bend housing / Drive Assembly): IPS coupling section is composed by two assemblies: the Adjustable Bend Housing (ABH) and the Drive Assembly.
Adjustable Assembly: The IPS motor is a steerable tool provided with a tree pieces adjustable bend section. This bend housing can be easily adjusted at rig site from 0° to 3° in varying increments to provide a wide range of build rates for the desired applications.
Drive Assembly: The Drive Assembly connects the lower section of the rotor and the upper section of the Drive Shaft. This Drive assembly transmits the rotational speed and torque from the rotor to the drive shaft. The drive assembly converts the eccentric rotation of the rotor to the concentric motion of the drive shaft.
BEARING SECTION The mud lubricated bearing section is composed by the thrust bearings, radial bearings and the drive shaft. The thrust bearings support the downthrust of the rotor and the reactive upward loading from the applied weight on bit. The radial bearings are used in the upper and lower ends of the bearing section to resist and absorb lateral loads of the drive shaft. Directional applications generates higher side loading on the drive shaft and the radial bearings. This bearing section is lubricated and cooled by 5-10% of the drilling fluid. The Drive Shaft transmit axial and torsional loadings to the bit.
Bit Box: The lower connection of the motor is named bit box, and basically is a API Regular Box to connect the drill bit.
Near Bit Stabilizer:
The IPS bearing housings are available with screw on stabilizers and screw on slick sleeves. Depending on the Directional job, The stabilizer sleeve can be installed and torqued on the rig floor easily. When stabilization is not required a slick sleeve can installed on the bearing housing.
MOTOR OPERATION IPS recommend the following procedures and guidelines to get the best performance of our lubricated mud motors. All the IPS motors are properly inspected and tested at our shop before sending to the well site. To avoid a bit or BOP damage by testing the motor without the bit attached. A thread protector should be installed on the bit box for the lifting operations and removed before the flow test. To prevent motor damage only apply rig tongs on the identified areas of the motor. Note: Use properly your PPE during the motor test on the rig floor. 1.- Make up the motor to the kelly or top drive and lower the motor until the bit box is still visible bellow the rotary table. 2.- Start the mud pumps, increasing until the bit box starts spinning. Record the flow rate and the pressure. The pressure recorded will be the no load pressure differential. 3.- Gradually increase the flow rate until reach the minimum flow rate for the specified motor. Record the flow rate and the pressure. Caution: to avoid the Bearing Section damage do not extend the operating time at very low flow rates without the bit attached to the motor. 4.- Be alert to excessive noise from the bearing section, specially if the motor has been used before without being serviced or if the motor has been unused for an extended period of time. 5.- Be sure that a proportion of drilling fluid is coming out of the motor above the bit box. Five to ten percent of the total flow coming out from this part is acceptable. 6.- Turn off the pumps, then procced to check the Bearing Clearance or
Thrust Bearing Wear: Measure the Off Bottom Gap: Lift the motor off the rig floor, let it hanging with no weight on the bit box, measure the distance between the bottom of the bearing housing and the top of the bit box, this measure is the Off Bottom Gap (D1). Measure the On Bottom Gap: Apply the weight of the motor on the bit box and measure the distance between the lower housing and the top of the bit box. This measure in compression is the On Bottom Gap (D2). To calculate the Bearing Clearance or Axial Clearance in the motor substract D2 fromD1. This measure do not be exceed the recommended clearance value.
7.- Once finished the surface test, the next step is attach the drilling bit to the bit box using a bit breaker while holding the lower end of the bit box with a rig tong (directly above the bit box), be sure the regular pin conection of the bit is cleaned and use dope before the bit instalation. Caution: to prevent internal connections back off avoid holding the bit box and rotating the motor counter clockwise, or holding the drilling motor and rotating the bit box clockwise. 8.- If is necessary to set the Adjustable Bend Housing follow the instructions located in the appendix of this handbook.
Tripping in the hole: To prevent damage to the Drilling Motor, IPS recommend be care when tripping in the hole: • Travel in at controlled speed to avoid damage. • Take spacial care while passing the BOP, casing shoes, liner hanger, striking brindges and near to the bottom. • In case of find tight spots proceed to ream starting pumps and reaming slowly, rotate periodically the drill string to prevent sidetracking. Excessive reaming operation may reduce the motor life. •In case of tripping in extreme depths or high temperatures, periodic stops of circulation are required to break for circulation. Following this point you can minimize the risk of bit plugging and help to maintain cool the drilling motor preventing high temperature damage. Every 500 to 1,000 ft is recommended circulate for a few minutes with the minimum flow rate and pressure to star the motor. •IF a PDC bit is being used, do not circulate through the motor with no WOB for long periods of time, the vibrations generated in the motor may damage the drilling bit cutters. •IF extended circulation is required while trippin in the casing, avoid causing localized casing wear reciprocating the drill string. •Before reach the bottom, stop and break circulation, this prevents plugging jets or motor damage.
DRILLING When the BHA has been reached the bottom of the hole, IPS recommends operate the drilling motor in the following manner: 1. With the drill bit 3 to 6 feet off bottom, starts the pumps and gradually increase the flow rate to the desired for drilling. Do not exceed the mámimum operating pressure for eah type of IPS mud motor. 2. Record the flow rate and the stand pipe pressure. This will be the unload or the Off Bottom Pressure. With ths pressure you can obtain the operation torque using the performance motor charts. This pump pressure will be more than the calculated due side loads effects between the bit and the hole diameter. 3. After a short period of circulation, lower the bit to bottom and slowly increase the weight. The torque can be affected by a uncirculated hole, prior orienting the drilling motor the hole should be cleaned. The bottom hole can be claened by slowly rotating the bha. This prevent buildup and sidetracking. 4. Orient the bha as the desired tool face and slowly apply WOB. Increasing WOB increases the pump pressure and decreasing WOB reduce it. The difference between the pressure off bottom and on bottom pressure is the Differential Pressure. Drilling keeping stady WOB and flow rate constant drives steady pump pressure. To mantain a constant tool face orientation this parameters should be considered.
Operative considerations: For the best performance of the drilling motor is necessary follow the operation guidelines: •More WOB will increase the Differential Pressure and Torque. •Reducing WOB will decrease the Differential Pressure and Torque. •Exceeding WOB limits may cause damage to the bearing pack and/ or the Power Section. •Apply excessive tension in case of stuck may cause damage to the bearing pack. •Pumping higher volume than the recommended in the technical specifications sheets can damage the drilling motor. •Exceeding the Maximum Differential Pressure result in premature wear or damage to the Elastomer or the Stator. •Avoid continuous stalling of the motor.
Drilling References: Since the mud motor is an hydraulically operated device, the principal reference for operational issues is the stand pipe pressure gauge. Using readings from the pressure gauge is more accurate because those values are not affected in case of wall hanging in the sliding drilling mode
Drilling Pressure: Adding WOB increase the surface pressure, as the drilling bit drills off this pressure decreases. As told before, the stand pipe pressure gauge can be used as an indicator of bit weight as well as torque. When the pressure gauge readas the desired operational pressure the driller stops adding WOB and a drill off occurs. The pressure will gradually fall allowing the driller using more WOB.
Reactive Torque: The IPS drilling motor produce clockwise rotation of the drilling bit. As WOB is increased, the differential pressure increases and the reactive torque is developed in a counter clockwise direction on the motor housings. As the amount of torque required to turn the bit reduces, the reactive torque reduces. As torque required to turn the bit increases, the reactive torque increases. The reactive torque reaches its maximum when the motor stalls. Reactive torque must be considered when orienting the drilling motor in the desired tool face orientation.
Drilling Motor Stall:
Stalling occurs when the power section is not cappable to rotate and to provide enough torque to the drilling bit because when the motor differential pressure exceeded the maximum and then the backpressure of the driling fluid deforms the elastomers of the stator causing that the drilling fluid pass straight in the motor without producing rotation in te bit. Motor stalling can produce quickly serious stator elastomer damage When the motor stalls, the motor must be restarted, lifting the tool from the bottom hole. IPS recommends the following steps to restart a stalled drilling motor: • Stop the rotary table (If rotating). • If needed turn the pumps off or reduce the flow rate at minimum. • Release the trapped torque using the rotary table brake. • Lift the drilling bit off bottom hole to allow pressure drop off. • Starts the mud pumps and gradually raise the flow rate to desired. • Orient the motor or start the drilling string rotation. Following the above procedure in case a motor stall will reduce the possibility of motor damage as well as connection back-off. Stall pressure is about twice the recommended optimum differential pressure across the motor. Caution: Operating the motor in a stalled condition, even for a short period of time, can seriously damage the motor. Stalling can provocate “chunking” of the stator elastomer. Once a stator is chunked, motor performance will dramatically decrease or possibly the drilling motor could not work. Motor Stall be caused by a single or a combination of the following : • Excessive WOB • Excessive string RPM • Excessive AKO setting • Excesive DLS • Inadecuate hole cleaning • Drill bit wear or damage • Sudden change in formation • Stick Slip
MICRO STALLING Micro Stalling may occur under high loading conditions for short time or rotating in high doglegs. In this form of stalling the bit locks up and the power section of the motor is not capable of providing enough and become stationary, and the stator, transmition, and driveshaft assembly are subjected to stall load. The bit then begins to rotate again, and the stall condition is removed. Micro stalls are of very short duration, and usually are not detectable at surface. Has the same characteristics and adverse affects as regular Stalling. Micro Stalling may occur as the result of stick slip.
DRILLING MOTOR ROTATION / DRILL STRING ROTATION Performance and Steerable applications require to rotate the drillstring, when rotating the drill string the motor rotate also. There are many reasons to rotate the drillstring: • Directional control • Reduce wellbore friction (reduced torque & drag) • Hole cleaning (transport the cuttings) • Penetration rate • Differential sticking Its recommended to use the minimum drill string RPM to prolong the drilling motor life. A maximum drillstring speed of 60 RPM is recommended, In favorable conditions, drillstring RPM can be increased to 100 RPM, with an absolute maximum of 120 RPM for short periods. Is not recommended to rotate the drilling motor at a setting greater than 1.75°. Drillstring rotation and therefore motor rotation increases the total mechanical loading effects on many drilling motor components. In steerable applications, the angle of the adjustable bend housing and higher wellbore doglegs can have a large impact on the stress level of a motor component. The two most common problems associated with drill-string rotation are component fatigue and connection back-off. Fatigue is a function of stress level and the number of load cycles at that level. Increasing RPM increases the number of load cycles within a given period of time, thereby potentially reducing component life. Back reaming at full drilling flow rates and rotary speeds is not advised. A minimum reduction of 30% of flow rate and 50% of drillstring RPM is recommended when back reaming.
TRIPPING OUT Prior to tripping out is recommended to circulate the drilling fluid at least a “buttom up” time to clean the wellbore. Care is required when pulling the drilling motor through tight spots such as liner hangers, casing, casing shoes, and BOP to minimize possible damage to both the drilling motor and the wellhead components. Drill string rotation is permissible to assist with the removal of the drill string. • When tripping out, the rotary table should not be used to break out connections of steerable assemblies with a high build-rate angle. • Control tripping speed to avoid swabbing the hole. • Reduce tripping speed when nearing casing shoe points. • Avoid excessive back-reaming as it may shorten motor life.
Procedures After Tripping Out: 1. Remove remaining fluid from the motor by placing the bit in a bit breaker. 2. Secure the motor body above the rotating bit sub with rig tongs. 3. Rotate the rotary table and bit counter-clockwise, draining the fluid out the top of the motor. 4. After the bit has been removed, spray water directly through the bit box. This will wash out the ports above the drive shaft and help clean the bearing section. 5. If the tool is to be stored for an extended time before re-use, flush the motor with clean water. Rotate the outer bearing housing to remove traces of the drilling fluid from the bearing stack. Pour a small amount of mineral oil or equivalent into the motor to protect the internal components from rusting or seizing. Do not use a dieselbased oil. 6. Dope the bit box and top sub box. install a thread protector into the box connections at each end.
DRILLING MOTOR TROUBLESHOOTING
DRILLING MOTOR SPECIFICATIONS AND PERFORMANCE CURVES This section of the handbook is intended to describe the technical specifications, performance curves and predictive buildrate tables. The drilling motors are categorized by OD size . There are different configurations for each drilling motor size to cover a wide range of drilling applications.
Drilling Motor Technical Specifications: In this section you will find technical specifications and operational parameters for every configuration by size of drilling motor. Recommended Operating Limits These values are the recommended limits for the power section: • Flow Range: The acceptable flow range through the power section. • Maximum Pressure: Pressure drop through motor when off bottom (no load). • Speed Ratio: The number of revolutions of the rotor per galon when no load is on the power section. • Speed Range: The output speed range of the power section with no load. • Maximum Torque: Output torque of the power section at max pressure.
Drilling Motor Performance Curves: The performance curve shown compares the output speed characteristics at high, mid and low flow rates for an specific power section. Also shown is the output torque for the power section. Output torque is dependant only on pressure and power section profile. For drilling motor differential pressure Is recommended one half of the motor stall pressure. • Differential Operating Pressure in psi is shown on the horizontal axis. This is the difference between the actual recorded on-bottom (with load) and off-bottom (no load) pressures. • Motor Speed in RPM is shown on the left axis. • Motor Torque in lb-ft is shown on the right axis. • Max Pressure is shown on the chart as a dashed vertical line. This is the maximum recommended load for continuous service. For flow rates in between those listed, interpolate an approximate point vertically between the 2 closest curves.
Build Rate Factors: In steerable applications, many factors affect the build rate of the drilling motor. These factors are: tool size to hole size ratio, flow rate, drilling fluid type, hole erosion, formation anisotropy, placement of stabilizers, bottom hole assembly (BHA), motor bend angle and distance from bit to bend, and the type of bit used. Following these recommendations can minimize these factors affecting build rate: • The lower the tool-size to hole-size ratio, the better the build rate. • The placement of pads and the use of a near bit stabilizer on the BHA has a significant impact on achieving a good build rate. • Some formations does not allow good build rates, and these types of formations should be identified while planning the drilling program. • Build rate is directly related to bend housing angle and the distance from the bit to the bend. • Changing the WOB can cause the build rate to change. Generally, an increase to the WOB causes the build rate to increase.
Build Rate Predicted Tables: The build rate tables are generated from a “three-point” geometry of the drilling assembly. Since any three points not in a line describe an arc, the top of the motor or a stabilizer located at the top of the motor, the adjustable bend housing, and the drill bit form such an arc. Figure 1 shows the basic three-point geometry and formula used to generate the build rates. Below are some notes regarding the predictions for the build rates. • The build rate prediction values can vary as the gauge and placement of near bit stabilizers are changed. • When the motor is sliding or during the rotation of a bent motor, it is assumed that a standard gauge hole is being drilled. • A short-gauge bit will produce better directional tendencies than an extended-gauge bit. • The formation is assumed to be homogeneous. Variations of formation hardness and type are not considered. • The tables assume all stabilizers are 1/8” (3.2 mm) under-gauge. • The build rate prediction values should be regarded as estimates only. Formation characteristics, bit profile, BHA design, and drilling parameters can all affect the directional response. • The units for build rate prediction are in degrees per 100 ft.
TEMPERATURE IPS Drilling Motors are designed to cover a wide range of temperature aplications, this range includes Standard Temperatures bellow to 250°F, High temperatures above 250 °F and up to 375°F. Downhole temperature is one of the important factors who affect on performance and life of a drilling motor. For a best performance and life the drilling motor must be set up and operated according to the downhole temperatures it will be subjected to. The component most affected by temperature is the stator elastomer. As temperature increases the elastomer swells and the mechanical properties of the elastomer are affected. A combination of these two effects have the following results: • Increased interference fit between rotor and stator • Increased friction and heat build up (heat build up accelerate elastomer failures) • Hard spots form in elastomer due to heat build up • Elastomer more susceptible to chunking • Reduced life expectancy • Premature wear on rotor and stator • Increased risk of downhole failure The power section can be configured considering the effects of temperature. The correct interference fit between the rotor and the stator must be selected based on the power section configuration and expected operating temperature. Elastomers designed for higher temperatures can be used to help improve life and performance.
High Temperature Guideline: • Follow standard shallow test and staging procedures to properly condition and test downhole motor and drilling tools, monitor borehole temperature, and prevent any sudden surge of pressure due to pipe fill. • Upon observing temperatures of 260ºF (125ºC) stop and circulate cool drilling fluid for 30 minutes or as long needed to lower the temperature of the BHA. • At 280ºF (140ºC) or higher use the same circulation procedure described above every 1000 ft (300m), approximately 10 stands, until reaching operating depth. • If reaching a circulating temperature of 340ºF (170ºC) and there exists a need to stop circulating for any extended period of time, the BHA must be tripped up hole to either the casing shoe or to the depth at which the static temperature is less than 260ºF (125ºC). This is to minimize the exposure time of the tools to temperatures greater than 350ºF (180ºC) and to prevent any issues associated with this temperature. • When initially drilling keep the operating differential pressure of the motor to a minimum for 30 to 60 minutes. • Stop drilling every 500 to 1000 ft (150 to 300m) to circulate until the drilling fluid cools the drilling motor. The temperature should be lowered as much as possible. • Maintain low operating differential pressure, slowly increasing until scaled operating differential pressure is achieved. Maintain that or less for drilling. • It is recommended to never go above a 200 psi operating differential pressure if circulating temperatures are above 300ºF (150ºC). • If a motor is run in temperatures greater than 260ºF (125ºC) it must be laid down when tripped to surface and returned to base for service and reline. Do not re-run.
DRILLING FLUIDS Circulating Fluids: • Additives may degrade at higher temperatures. • Chemical reactions are accelerated at higher temperatures. • Accelerated corrosion can occur at higher temperatures. • Oil based mud tends to be more stable than water based mud at higher temperatures. • Oil based mud will react more with the elastomer at higher temperatures leading to accelerated elastomer degradation.
Drilling Fluids The IPS Drilling Motor is designed to operate with most types of drilling fluids such as fresh or salt water, oil based fluids, additives for viscosity control or lost circulation, and nitrogen gas. The most fluid sensitive component in the drilling motor is the elastomer lining in the stator.
Oil Based Fluids: • Oil based drilling fluids will affect the integrity of an elastomer. • Elastomers perform better in mineral based fluids over diesel based fluids. • Aniline point is a measure of the affect of an oil based fluid on an elastomer. • Recommended pH level should be between 4 and 10.
Aniline Point The Aniline Point of circulating fluids has generally been used as an indicator of the tendency of a circulating fluid to degrade elastomer components. Aniline Point is the temperature at which a specific volume of aniline completely dissolves in a similar volume of drilling fluid sample. • Aniline point and temperature must be taken into consideration when selecting motor set ups, fits, and operating parameters. • It is recommended that any drilling fluid used have an aniline point greater than 93°C (200°F) and have less than 2% aromatics. Low aniline point oil based drilling fluids can damage stator liner and cause premature failure. • It is recommended that the operating temperature of the fluid be lower than the aniline point. Operating outside the above parameters will tend to excessively swell the elastomer. This will cause premature wear reducing motor performance and life. • The use of stators that compensate for elastomer swelling in hydrocarbon based fluids or have larger clearances are recommended.
Brine / Salt: Drilling fluids containing chlorides can reduce rotor and stator life due to corrosion, especially at elevated temperatures. Special attention should be paid to the internal coatings when the chloride concentration is in excess of 30,000 PPM. The motor should be flushed and serviced as soon as possible if it has been exposed to chlorides. High chloride concentrations will attack the base metal under coatings such as the chrome on the rotor. This will cause the chrome to flake off forming sharp edges on the surface. These sharp edges will accelerate the wear on the stator elastomer. When these components become damaged the drilling motor’s performance is dramatically reduced.
Lost Circulation Material (LCM): Typical lost circulation materials such as calcium carbonates, walnut shells, cellophane flakes and cellulose fiber (among others) can be used safely with mud lubricated drilling motors, however, a few considerations must be made when doing so. • Particle size should be less than 1/8” for 4 ¾” and smaller drilling motors. • Particle size should be less than 1/4” for 6-3/4” and larger drilling motors. • Use medium to fi ne LCM, max 40 lbs/bbl (114 kg/m3). • Larger particle sizes or heavy concentrations of fibrous material will have a tendency to start plugging up radial bearings or port nozzles in the drilling motor and lead to premature wear or circulation problems. • MWD tools usually present more limitations with LCM than drilling motors. In order to avoid plugging the system lost circulation material should be added slowly, away from the pump intake. A pre-mix system would be the preferred means of usage.
Solids and Sands: • Percentage of solids in a drilling fluid should be kept to a minimum. • Solids content should be kept below 5% . • Fine abrasives such as sand should be kept lower than 0.5%. • Solids and sands are extremely damaging to the stator elastomer. • All solid additives with rough or sharp surfaces should be avoided.
Mud Density: The drilling fluid density, or mud weight, will have an affect on the overall performance and life of the drilling motor. Heavier muds will have a tendency to wear the motor faster than lighter muds. • Less than 12 lbs/gal and 0.5% sands will prevent possible washing. • Greater than 16 lbs/gal will cause abnormal wear. • Max mud density should be less than 19 lbs/gal. Solids, LCM or any other additives to the drilling fluid must be taken into consideration and may increase the wear rate or reduce the maximum density that the motor can handle. Solids, LCM and additives on the drilling fluids impact on motor performance and/or motor life.
MOTOR Technical Specifications