2 Downhole Mud MotorDownhole 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.
3 Positive Displacement Motors IntroductionAll 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.
4 Positive Displacement Motors IntroductionThe 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.
5 Positive Displacement Motors IntroductionThe 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.
6 Positive Displacement Motors IntroductionDump valve: allow the fluid circulation when the pressure below a certain threshold.Multistage power sectionSurface-adjustable bent housingThrust and radial-bearing section
7 Positive Displacement Motors Limitations and Benefits 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.
8 Positive Displacement Motors DesignA PDM is essentially constituted of two helical gears, one inside the other and rotating around their longitudinal axis which parallel but spaced between each other.The external gear has one more thread or tooth than the internal element.
9 Positive Displacement Motors DesignThe internal element is set so that all the threads or teeth are constantly in contact with the external element.The cross sections of helical elements consist of coupled profiles achieved by the epicycloid and hypocycloid combination, whose generator circles have a diameter equal to the distance between the longitudinal axis of the two helical elements.
12 Introduction to Hypocycloid Positive Displacement MotorsDesignIntroduction to Hypocycloid
13 Positive Displacement Motors DesignIf N = 1, the diameter of the small circle is the same as that of the large circle and the hypocycloid is a circle called 1-lobe hypocycloid. Similarly, if N = 2, the diameter of the small circle is half of the diameter of the large circle and the hypocycloid is a line with its length equals the diameter of the large circle called 2-lobe hypocycloid.K
15 Positive Displacement Motors DesignAssuming the diameter of the base circle of the N-lobe hypocycloid is Db.The diameter of the generator circle is Db/N.The eccentricity of this pump (the radius of the generator circle):The diameter of the stator is defined as the sum of the diameter of the base circle and the diameter of the semicircle at the cusp as:Ds = 2eN + dDiameter of the rotor:orK
17 Positive Displacement Motors DesignThere will be (N-1) free spaces between the rotor and the stator.The total areas, A = S1 + S2 + S3, remains constant.
18 Positive Displacement Motors PerformanceThe flow area of a PDM:This new equation can be used to calculate the flow area of any given PDM, regardless to single or multi-lobe PDM.The pitch length (P) is defined as a length of 360o rotation of the crest trace of one helix lobes.Note that N is the number of lobe of the stator. For a single lobe PCP, K = 2 and Ps = 2Pr.K
20 Positive Displacement Motors PerformanceThe theoretical pump factor is the total fluid volume that the pump can discharge as the rotor turns one cycle, which can be expressed as,The pump capacity when the rotor turns with a speed of w is given as,K
21 Positive Displacement Motors PerformanceIf the pressure drop, DP (psi), flow rate, Q (gal/min), and motor efficiency are known, it is possible to calculate the motor hydraulic horsepower:The motor efficiency takes into account fluid leaks along contact surfaces between the rotor and stator, various friction losses, and entry and exit effects.If the bit rotational speed, w (RPM), is known, the rotary torque can be calculatedN
28 Positive Displacement Motors PerformanceA pressure of 100 psi is required to start the rotor shaft against the internal friciton of the rotor moving in the elastomer stator.With constant flowrate, the PDM will run at near constant speed, w = 408 RPM.As WOB increases, DP increases leading to an increase in torque and HP.WOB = 0, w = 408 RPM. DP will drop down to about 100 psi. This DP is to overcome the internal friction.The amount of torque and power can be determined by the pressure change at the standpipe between the unloaded and loaded conditions.If the DP is more than the pressure limit of 580 psi --> leakage and failure
30 Positive Displacement Motors ExampleA 6 ¾-in OD PDM of a 1:2 lobe has rotor eccentricity of 0.6-in., a reference diameter (semicircle diameter or rotor shaft diameter) of 2.48-in. and a rotor pitch length of 38-in. If the pressure drop across the motor is determined to be 500 psi at a circulation flowrate of 350 GPM with 12 ppg fluid, what is the torque, rotational speed and the horsepower of the motor. Assume the motor efficiency is 0.8.
33 Downhole Mud Motor Turbine 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.
35 Downhole Mud Motor Turbine Motors The 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.
36 Downhole Mud Motor Turbine Motors 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.
37 Downhole Mud Motor Turbine 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.
38 Downhole Mud Motor Turbine Motors Turbine 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
39 Downhole Mud Motor Turbine Motors Torque definition: Power definition: Therefore, turbine power is a parabolic function of the bit speed N.The maximum power is achieved at
40 Downhole Mud Motor Turbine 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.
41 Downhole Mud Motor Turbine Motors Turbine 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.
43 Downhole Mud Motor Turbine Motors The stall torque is 2,824 ft-lbf. The runaway speed is 1,614 rpm.Maximum horsepower of 217 HP at a speed of 807 RPM.The torque at the peak horsepower is 1,412 ft-lbf or ½ of the stall torque.Circulation mud density of 10 ppg at 400 gpm, the DP = 1,324 psi. This pressure is approximately constant through the entire speed range of the motor.If WOB increase, the speed will be slow. Maximum HP = 217 at 807 RPM
44 Directional Deviation Tools Rotary Steerable Systems (Geometric Steering)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
45 Directional Deviation Tools Rotary Steerable Systems
46 Directional Deviation Tools Rotary Steerable Systems The advantages of this technology are many for geoscientists & drillersThe flow of drilled cuttings past the BHA is enhanced. This results in improved transport of drilled cuttings to the surface.Continuous rotation help to reduces drag and risk of sticking.Continuous rotation improves ROPContinuous rotation also provides better weight transfer.Continuous rotation helps borehole walls smoother than those drilled with mud motors; and hence provides higher quality measurements of formation properties.
47 Directional Deviation Tools Rotary Steerable Systems Rotary 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 bitPoint the bit
48 Early deviation control while rotating presented in 1955. Directional Deviation ToolsRotary Steerable Systems – Push the BitEarly deviation control while rotating presented in 1955.
49 Directional Deviation Tools Rotary Steerable Systems – Push the Bit A 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.
50 Directional Deviation Tools Rotary Steerable Systems – Point the Bit
51 Directional Deviation Tools Rotary Steerable Systems – Point the Bit 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.
52 Directional Deviation Tools Rotary Steerable Systems Rotary 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.
53 Directional Deviation Tools Special Bottomhole Assemblies 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.
54 Directional Deviation Tools Well Trajectory Planning Type I: Build and HoldType II: Build, Hold and Drop (S shape)Type III: Continuous BuildType IV: Build, Hold, and Build.
55 Directional Deviation Tools Well Trajectory Planning Type I — Build and Hold: This pattern employs a shallow initial deflection and a straight-angle approach to the target. It is most often used to reach single targets at moderate depths, and sometimes for drilling deeper wells with large horizontal departures.Type II — Build, Hold and Drop ("S" pattern): After a relatively shallow deflection, this pattern holds angle until the well has reached most of its required horizontal displacement. At that point, angle is reduced or brought back to vertical to reach the target. The Type 2 pattern is most applicable to wells exposing multiple pay zones, or wells subject to target or lease boundary restrictions.
56 Directional Deviation Tools Well Trajectory Planning Type III — Continuous Build: Unlike the Type 1 and 2 patterns, this trajectory has a relatively deep initial deflection, after which angle is maintained to the target. The continuous build pattern is well-suited to salt-dome drilling, fault drilling, sidetracks and redrills.Type IV —Build, Hold and Build: This is the general pattern describing horizontal wells. The decision to drill horizontally is primarily based on reservoir engineering and reservoir management considerations.
57 Directional Deviation Tools Well Trajectory Planning
58 Directional Deviation Tools Special Bottomhole Assemblies - Holding 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.
62 Directional Deviation Tools Special Bottomhole Assemblies - Building
63 Directional Deviation Tools Special Bottomhole Assemblies - Dropping
64 Directional Deviation Tools Special Bottomhole Assemblies - Holding
65 Directional Deviation Tools Special Bottomhole Assemblies As 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.
66 Directional Deviation Tools Special Bottomhole Assemblies In 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.
67 Directional Deviation Tools Deflection ToolsAlthough 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:Directional wedges (Whipstocks)Jet bits with oriented nozzles
68 Directional Deviation Tools Wedges or Whipstocks
69 Directional Deviation Tools Wedges or WhipstocksThe 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.
70 Directional Deviation Tools Jet Bits with Oriented Nozzles
71 Directional Deviation Tools Jet Bits with Oriented Nozzles 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.
72 Survey ToolsDepending on the type of tool, measuring instruments record the following parameters:Drift: the inclination of the wellbore from verticalAzimuth: the direction of the wellbore in the horizontal plane (i.e., the "compass direction," usually with respect to magnetic or true North)Toolface orientation: the azimuthal direction of a bent housing or other deflection tool
73 Mechanical Drift Indicator Survey ToolsMechanical Drift IndicatorThe oldest and simplest type of directional survey tool is the mechanical drift indicator
74 Mechanical Drift Indicator Survey ToolsMechanical Drift IndicatorThis device works on a pendulum, or "plumb-bob" principle.It gives no indication of azimuth, but measures only a well's inclination from vertical.It is used today for surface hole intervals, shallow vertical wells and other applications where dog-leg severity and horizontal departure are not likely to become significant problems.The use of this device typically involves two inclination measurements: an initial measurement, followed by one for verification purposes.
75 Survey Tools Magnetic Survey Tools A magnetic compass and angle-indicating unitA camera unit for recording measurements on a photographicA timer or motion sensor, which activates the device at a desired time or depth interval
78 Survey Tools Magnetic Survey Tools Magnetic survey tools record the inclination and azimuth at various points, or stations, along the well course. Two basic types of tools are available:Magnetic Single-Shot: Records one measurement, usually near the bottom of the well. It is comprised of a precision floating compass, a device to superimpose concentric circles (calibrated in degrees) with a plumb-bob type indicator, and a camera that photographs the plumb-bob and compass face to record both drift and direction.It cannot record compass directions inside regular drill collars or casing because steel pipe blanks off the Earth's magnetic lines of force. Thus, it is used only in open hole or inside non-magnetic drill collars.
79 Survey Tools Magnetic Survey Tools Magnetic Multi-Shot: Records multiple measurements of borehole drift and azimuth on a single run into the hole. It consists of a modified magnetic single- shot instrument with the single frame camera replaced by a multi-frame camera.It also has incorporated timing devices, including a motion sensor, and is used for multi-depth drift and direction measurements. Like the single-shot, It must be in an open hole or inside non-magnetic drill collars to measure compass directions.Magnetic survey tools can be dropped or pumped to bottom, lowered on slick line or wireline, or run as part of a measurement-while drilling (MWD) package. When tools are dropped to bottom--typically before tripping pipe--they can be recovered when the pipe is pulled, or else by means of an overshot.
80 Survey Tools Magnetic Survey Tools In place of camera-based devices, more modern magnetic survey tools offer solid- state electronic recording capabilities.These devices are armed by means of a surface computer, and then run like standard multi-shot tools.Survey data are recorded electronically using highly sensitive magnetometers and accelerometers, stored, and then retrieved and processed by the computer.Their main advantages are time savings, improved accuracy, continuous readings with surface readouts, and elimination of errors caused by manually reading film records.
81 Survey Tools Magnetic Survey Tools The 3-Axis Accelerometer contains three acceleration-sensing integrated circuits (IC’s), along with the associated electronics.Each of the accelerometers measures acceleration along one line and produces a signal on one of the three outputs. These three axes and three outputs are labeled X, Y, and Z.
82 Survey Tools Steering Tools Steering tools are used to measure drift, direction and tool face during semi- continuous drilling.An instrument package containing any of the tools mentioned above is sent downhole, and a coder converts data measurements to electrical pulses and transmits these to the surface through a shielded electric conduit to digital or TV- type displays / recorders.Thus measurements are available immediately at the surface for use in controlling hole direction.
83 Directional Drilling Tools Wireline Steering Systems
84 Directional Drilling Tools Wireline Steering Systems A wireline steering system consists of a bottomhole assembly that accommodates a measurement probe run on wireline. The probe employs magnetometers to measure direction, and accelerometers to measure hole angle. It also measures the orientation of the tool-face, and other parameters such as time, depth and tool temperature.The wireline is either run inside the drill-pipe or passed through a side-entry sub, and connected to a surface computer, which processes the information and provides a remote readout. The operator can then correct the tool-face angle as necessary to maintain the well on course.
85 Directional Drilling Tools MWD and LWD SystemsOne of the most important advances in modern petroleum technology has been the development of real-time Measurement-While-Drilling (MWD) systems to transmit drilling and directional information, and Logging-While-Drilling (LWD) systems to provide formation evaluation data.Angle, azimuth, drill bit position and trajectory,Monitor penetration rate, actual WOB, downhole torque and drag, etc…Compute Ppore and get an early warning of potential overpressured zoneDetect and correlate geologic markers and formation topsEvaluate formations even as they are being drilled.
86 Directional Drilling Tools Measurement While Drilling (MWD) MWD systems record measurements at or near the bit as drilling proceeds, and the data are transmitted immediately to the surface by pressure pulses in the mud column or by other methods that do not require an electrical conduit.This eliminates many problems common to other measurement systems. Along with directional data, these systems can also carry third-party tools to measure key drilling parameters (e.g., rate of penetration, rotating speed, mechanical efficiency log, sticking pipe indicator, strain gauge, temperature, pressure, etc.) and formation evaluation data (e.g., gamma ray, resistivity, conductivity, neutron, etc).
87 A schematic diagram of an MWD/LWD system Directional Drilling ToolsMWD and LWD SystemsA schematic diagram of an MWD/LWD system
88 Typical MWD/LWD configurations in various bottomhole assemblies Directional Drilling ToolsMWD and LWD SystemsTypical MWD/LWD configurations in various bottomhole assemblies
89 Directional Drilling Tools MWD and LWD SystemsMud pulse telemetryThis is the most common method of data transmission used by MWD (Measurement While Drilling) tools. Downhole a valve is operated to restrict the flow of the drilling mud (slurry) according to the digital information to be transmitted. This creates pressure fluctuations representing the information. The pressure fluctuations propagate within the drilling fluid towards the surface where they are received from pressure sensors. On the surface, the received pressure signals are processed by computers to reconstruct the information. The technology is available in three varieties - positive pulse, negative pulse, and continuous wave.
90 Directional Drilling Tools MWD and LWD SystemsMWD tools operate by creating pressure pulses in the mud column, in response to inputs from the various sensors. Depending on the type of tool, the pulses may be positive, negative or continuous. These pulses are converted into electronic signals, which are processed and displayed at the surface.
91 Directional Drilling Tools MWD and LWD SystemsPositive PulsePositive: tools briefly close and open the valve to restrict the mud flow within the drill pipe. This produces an increase in pressure that can be seen at surface. Negative Pulse: tools briefly open and close the valve to release mud from inside the drillpipe out to the annulus. This produces a decrease in pressure that can be seen at surface. Continuous Wave: tools gradually close and open the valve to generate sinusoidal pressure fluctuations within the drilling fluid.
92 Directional Drilling Tools Magnetic Survey Tools
93 Directional Drilling Tools MWD and LWD SystemsThe basic components of the MWD instrument package include:a battery-powered pulser module: employs a continuous mud wave transmissiona sensor module containing tri-axial inclinometers to measure drift and tri- axial magnetometers to measure azimuth, along with T and P sensorsan electronics module.
95 Directional Drilling Tools MWD and LWD SystemsLWD tools operate on basically the same principles as conventional wireline logging tools. The dual resistivity shown in the Figure contains a gamma ray tool, and two sets of transmitters and receivers to provide shallow and deep resistivity readingsThe compensated density-neutron tool measures density and neutron porosity in a manner similar to that of analogous wireline tools.
97 Directional Drilling Tools EMWD SystemsConventional MWD and LWD systems rely on pressure pulse type telemetry in incompressible drilling fluids. When compressible fluids are used in low-pressure drilling (e.g., Underbalanced drilling), the pulses are absorbed by the drilling fluids, resulting in signals that are undetectable at the surface. In these situations, electric-magnetic induction (EMI) telemetry is used.The MWD tool with (EMI) telemetry is called EMWD.