Directional Drilling Tools and Techniques

(adsbygoogle = window.adsbygoogle || []).push({}); Directional drilling tools are specialized tools used in the oil and gas industry to steer the wellbore and control the trajectory of the drilling operation. These tools allow operators to drill wells at angles or in directions that would not be possible with conventional vertical drilling methods. Introduction to Directional Drilling Tools and Techniques The planning, equipment, tools and procedures involved in drilling non-directional wells also apply to directional ones. Over and above these basic considerations, however are a number of requirements that are unique to directional drilling. These requirements may relate to any or all of the following areas: Planning and calculating an optimal well trajectory Employing specialized equipment (e.g., downhole motors, survey instruments, steering tools, measurement-while drilling (MWD) and logging-while-drilling (LWD) systems, non-magnetic drill collars and articulated drill pipe) Specially designing bottomhole assemblies to help control the well course and transmit weight to the bit Minimizing drill pipe and casing wear in highly deviated holes (e.g., extra drill pipe protectors, increased casing centralization) Increasing hydraulics capacity to ensure effective annular hole cleaning, and using special drilling fluid lubricants to reduce torque and drag Well Trajectory Planning https://youtu.be/8aHZW4btPc4 (adsbygoogle = window.adsbygoogle || []).push({}); The starting point in planning a directional well is to establish the target coordinates with respect to the surface location, and get an idea of the well course, or trajectory. Well trajectories generally follow one of four basic patterns (Figure 1): FIGURE 1 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. 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. Having established a basic well profile, the next step is to plan the trajectory in detail, again starting with the bottom hole target (Figure 2, Directional drilling parameters). FIGURE 2 We express the target location in terms of its true vertical depth (TVD) and horizontal departure, or throw. The target diameter or radius dictates how much control we have to exercise over the well trajectory. Generally, the greater the degree of control, the higher our drilling costs. We should therefore establish the largest target that will ensure our meeting well objectives. Except for the special case of slant drilling, all wells start off as more or less vertical. They become directional only when we reach the kick-off depth (KOD): the point at which we begin the incremental building of drift angle, or inclination from vertical. Inclination is expressed as degrees per unit of drilled interval (typically [latex]\tfrac{^{\circ}}{100\ ft}[/latex] or [latex]\tfrac{^{\circ}}{100\ m}[/latex]). The turn-off depth (TOD) is a point at which we change the hole direction, or azimuth, as measured with respect to true North. For example, if a target is located at a direction of 20° from North in relation to the surface location, the azimuth at the turn-off depth is N20°E. The build-rate angle and drop-rate angle, respectively, refer to the incremental increase or decrease in inclination from vertical, while the turn-rate angle is the change in azimuth per 100 feet or meters of hole section. Because of drill string rotation, bits tend to "walk" to the right in the horizontal plane. To account for this natural drift, it is common to initiate the turn of the well path with a specified lead angle (LA) to the left of the target. The required magnitude of the lead angle is generally determined from offset well records. Because bits also tend to "fade" (i.e., lose angle due to gravity); the lead angle should therefore be high with respect to the average angle. This section summarizes the equations used to calculate directional plans in the vertical plane for the Build and Hold, Continuous Build and Build, Hold and Drop well patterns. The reader may find derivations for these equations in Maurer (1966). Build and Hold Pattern (adsbygoogle = window.adsbygoogle || []).push({}); Calculation of the Build and Hold pattern requires the following data (Figure 3): (KOD) = kick-off depth, ft (HDY)t = target horizontal departure in the y plane, ft (TVD)t = true vertical depth, ft BR = build rate angle (°/ft) Rb = build radius (ft or m) t = total depth b = build FIGURE 3 Case 1: (HDY)t < Rb [latex]R_{b}= \frac{1}{BR}\cdot \left ( \frac{180}{\pi} \right )[/latex] (1) [latex]\theta_{b} = \tan^{-1} \dfrac{a}{b}-\cos^{-1}\left [ \dfrac{R_{b}}{a}\cdot \sin \left ( \tan^{-1}\dfrac{a}{b} \right ) \right ][/latex] (2) where [latex]a = \left ( TVD \right )_{t}-KOD[/latex] [latex]b = R_{b}-\left ( HDY \right )_{t}[/latex] θb= maximum angle of hole inclination at end of build. The total measured depth to target (TMD) equals [latex]TMD = KOD +\dfrac{\theta_{b}}{BR}+\dfrac{\left ( TVD \right )_{t}-KOD-R_{b}\cdot \sin \theta _{b}}{\cos\theta_{b}}[/latex] (3) and we can calculate kick-off depth as [latex]KOD = TVD - R_{b}\cdot \sin \theta _{b}-\dfrac{\left ( HDY \right )_{t}-R_{b}\cdot \left ( 1-\cos \theta_{b} \right )}{\tan \theta_{b}}[/latex] (4) Case 2: (HDY)t > Rb [latex]\theta_{b}= 180 -\tan^{-1} \left ( -\dfrac{a}{b} \right )-\cos^{-1} \left [\dfrac{R_{b}}{a}\cdot \sin \left ( \tan^{-1}\left ( -\dfrac{a}{b} \right ) \right ) \right ][/latex] (5) TMD and KOD are as defined in Equations 3 and 4. Continuous Build Pattern (adsbygoogle = window.adsbygoogle || []).push({}); The data required for the Continuous Build calculation (Figure 4) are the same as those required for the Build-and-Hold equations. The calculated horizontal departure in the y plane and the true vertical depth at a point i along the build section are as follows: FIGURE 4 [latex]\left ( TVD \right )_{i} = \left ( KOD \right )+R_{b}\cdot \sin \theta _{bi}[/latex] [latex]\left ( HDY \right )_{i}= R_{b}\cdot \left ( 1-\cos \theta _{bi} \right )[/latex] The total True Vertical Depth (TVD)t and the Total Horizontal Departure (HDY)t can be found by substituting the total build angle, θb, in Equations 5 and 6, respectively. The total Measured Depth is given by [latex]TMD = KOD + \dfrac{\theta_{b}}{BR}[/latex] Build, Hold and Drop Pattern Data requirements for the build, hold and drop pattern (Figure 5) are similar to those for the Build and Hold and Continuous Build patterns. The following equations are used to calculate the maximum angles of inclination: FIGURE 5 Case 1: Rb (HDY)t [latex]\theta_{b} = \tan^{-1}\left ( \dfrac{a}{b+R_{d}} \right )-\cos^{-1}\left [ \dfrac{R_{b}+R_{d}}{a}\cdot \sin \left ( \tan^{-1} \dfrac{a}{b+R_{d}} \right )\right ][/latex] (9) Case 2: Rb< (HDY)h ; Rb+Rd <(HDY)t [latex]\theta_{b} = 180 - \tan^{-1}\left ( \dfrac{a}{b+R_{d}} \right )-\cos^{-1}\left [ \dfrac{R_{b}+R_{d}}{a}\cdot \sin \left ( \tan^{-1} \dfrac{a}{b+R_{d}} \right )\right ][/latex] (10) The Total Measured Depth is [latex]TMD = KOD + \dfrac{\theta_{b}}{BR}+\dfrac{\left ( TVD \right )_{h}-KOD - R_{b}\cdot \sin \theta_{b}}{\cos\theta_{b}}+\dfrac{\theta_{d}}{BR}[/latex] (11) The calculations that define the well path in the horizontal plane can be described by the following equations: [latex]\left ( NS \right )_{i}= \Delta d_{i}\cdot \sin \left ( \dfrac{\theta_{i} + \theta_{i-1}}{2} \right )\cdot \cos \left ( \dfrac{\theta_{i}+\alpha_{i-1} }{2} \right )[/latex] (12) [latex]\left ( EW \right )_{i}= \Delta d_{i}\cdot \sin \left ( \dfrac{\theta_{i} + \theta_{i-1}}{2} \right )\cdot \sin \left ( \dfrac{\theta_{i}+\alpha_{i-1} }{2} \right )[/latex] (13) The incremental True Vertical Depth is [latex]\left (TVD \right )_{i}=\Delta d_{i}\cdot \cos \left ( \dfrac{\theta _{i}+\alpha_{i-1}}{2} \right )[/latex] (14) where (adsbygoogle = window.adsbygoogle || []).push({}); [latex]\left ( NS \right )_{i}[/latex] = incremental distance measured along north-south direction [latex]\left ( EW \right )_{i}[/latex] = incremental distance measured along east-west direction [latex]\Delta d_{i}[/latex] = an assumed incremental distance of hole section (generally 100 ft) [latex]\theta_{i-1}[/latex] ; [latex]\alpha_{i-1}[/latex] = inclination and azimuth at previous station (i−1) We may find the total distances by summing the total increments: [latex]\left ( TNS \right) = \sum\limits_{i= 1}^{n}\left ( NS \right )_{i}[/latex] (15) [latex]\left ( TEW \right) = \sum\limits_{i= 1}^{n}\left ( EW \right )_{i}[/latex] (16) [latex]TVD = KOD + \sum\limits_{i= 1}^{n}\left ( TVD \right )_{i}[/latex] (17) (adsbygoogle = window.adsbygoogle || []).push({}); Downhole Mud Motors https://youtu.be/zTij1OvFvOg (adsbygoogle = window.adsbygoogle || []).push({}); Downhole motors (commonly known as mud motors because they are hydraulically driven by the circulating drilling fluid as it moves down the drill string) have played an integral role in the advancement of directional drilling technology, and in "straight hole" drilling as well. 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. The distinguishing feature of downhole motors is that they 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 it in this direction throughout the bit run. 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. Positive Displacement Motors The 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. Or, in "crooked hole" formations, it can be run without these accessories as a deviation control tool. For maximum directional control with a minimum of trip time, we may use a motor with a bent housing. Figure 1 (Steerable positive displacement motor) illustrates a motor in which the bent housing is adjustable. FIGURE 1 The heart of the positive displacement motor is the rotor-stator assembly (Figure 2), consisting of a helicoidal rotor that moves within a molded, elastomer-lined stator. FIGURE 2 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. Positive displacement motors provide excellent steerability for deflecting or straightening the well course. In addition, they allow for increasing the bit RPM without increasing the drill string rotation, and for drilling with less weight-on-bit. This can result in higher penetration rates compared to drilling with a rotating kelly, along with reduced drill pipe and casing wear - an important consideration, especially when drilling high-angle holes. Positive displacement motors are available in a wide variety of sizes, rotating speeds, rotor/stator configurations and output characteristics, for a broad range of downhole conditions . Turbine Motors (adsbygoogle = window.adsbygoogle || []).push({}); A turbine motor (Figure 3) consists of multiple rotor/stator assemblies, which drive main thrust-bearing sections. FIGURE 3 Turbine motors operate at relatively high rotary speeds, and so are run exclusively with fixed cutter (PDC or natural diamond) bits. Some operators see this as an advantage in certain situations, in that these characteristics may help eliminate "bit walk" to the right, allow for higher bit weight (and thus improved drilling rates) and a smoother hole for logging and casing operations than a PDM would provide (von Flatern, 1991). 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. The operator and directional service company representative should consider the following basic information when selecting a downhole motor (von Flatern, 1991): Depths (kickoff point, target, etc.) Hole size Formation hardness Faulting Build rate Bottomhole temperature Conditions at the kickoff point (e.g., inside casing, sidetrack plug, etc.) Hydraulics program Mud program Rig pump capabilities (adsbygoogle = window.adsbygoogle || []).push({}); Rotary Steerable Systems (adsbygoogle = window.adsbygoogle || []).push({}); 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 (Figure 1: Rotary steerable system). 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. FIGURE 1 The advantages of this technology are many for geoscientists & drillers The flow of drilled cuttings past the BHA is enhanced because annular bottlenecks are not created in the wellbore. This results in improved transport of drilled cuttings to the surface, which in turn brings about better hydraulic performance and superior hole cleaning. Continuous rotation of the drill string eliminates the need to slide a steerable motor. This results in reduced drag and decreases the risk of sticking. Continuous rotation of the drill string improves penetration rates because there are no stationary components to create friction and reduce efficiency Continuous rotation also provides better weight transfer. This allows for the drilling of more complex wellbores, along with reduced wellbore tortuosity due to utilizing a more steady steering model. Well geometries are therefore less aggressive, and borehole walls are smoother than those drilled with mud motors. This is particularly beneficial for geoscientists, because it provides for higher quality measurements of formation properties. Rotary steerable systems are available from a number of vendors, including : Baker Hughes Inc. Calmena Energy Services Cathedral Energy Services General Electric Oil & Gas Gyrodata Halliburton Jindal Drilling & Industries Limited Key Energy Services Leam Drilling Systems LLC Nabors Industries Ltd. National Oilwell Varco Schlumberger Limited Scientific Drilling International Weatherford International Ltd. 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. The BHA directs the well path in the desired direction while keeping the orientation of the drilling trajectory separate from its rotation and the rotation of the drill pipe above it (Figure 2). (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 2 Rotary steerable systems are of two types - push-the-bit systems and point-the-bit systems. Both systems utilize complex working mechanisms to effect independent 3D directional control. Push-the-bit systems steer the bit by applying a side load that forces the bit laterally in the direction of the desired curve (Figure 3). Point-the-bit systems steer the bit by tilting the bit in the direction of the desired curve (Figure 4). FIGURE 3 FIGURE 4 (adsbygoogle = window.adsbygoogle || []).push({}); Specialized Bottomhole Assemblies https://youtu.be/jVi9QAWdMCA (adsbygoogle = window.adsbygoogle || []).push({}); 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. Examples of typical angle-building, angle-dropping and angle-holding BHAs are shown, respectively, in Figure 1, Figure 2 and Figure 3. FIGURE 1 FIGURE 2 FIGURE 3 (adsbygoogle = window.adsbygoogle || []).push({}); Deflection Tools (adsbygoogle = window.adsbygoogle || []).push({}); Although mud motors and rotary steerable systems are overwhelmingly the tools of choice for controlled directional drilling, there are other tools that may be of some use in certain areas. These include: Directional wedges Jet bits with oriented nozzles Directional Wedges Figure 1 shows a schematic of the wedge technique for deviating a wellbore. FIGURE 1 The wedge is attached to the bottomhole assembly by means of a shear pin. The assembly is lowered to bottom and oriented in the proper direction. The driller applies weight to set the wedge and shear the pin, drills ten to fifteen feet of undergauge hole, and then trips the tools so that 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. (adsbygoogle = window.adsbygoogle || []).push({}); Jet Bits with Oriented Nozzles Jetting bits with orienting nozzles can be effective at initiating deflection in very soft formations. Figure 2 illustrates the technique. FIGURE 2 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. (adsbygoogle = window.adsbygoogle || []).push({}); Survey Tools https://youtu.be/1ZoZ2DJ846Q (adsbygoogle = window.adsbygoogle || []).push({}); Depending on the type of tool, measuring instruments record the following parameters: Drift: the inclination of the wellbore from vertical. Azimuth: 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. Mechanical Drift Indicator The oldest and simplest type of directional survey tool is the mechanical drift indicator (Figure 1). FIGURE 1 This 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. 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. 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. The basic components of a conventional magnetic survey tool are as shown in Figure 2: FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); a magnetic compass and angle-indicating unit a camera unit for recording measurements on a photographic a timer or motion sensor, which activates the device at a desired time or depth interval 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 (Baker-Hughes Inteq, 1993). To prevent magnetic interference from the drill string,magnetic instruments must be run inside non-magnetic drill collars. They may be run with a collar, or "monel" sensor (Figure 2 When run in conjunction with a non-magnetic orienting sub or collar, they can be used to determine tool-face orientation Figure 3 illustrates a typical running assembly for a single-shot magnetic tool. Note the orientation sub at the bottom of the assembly, which is used to orient deflection tools for directional drilling. FIGURE 3 Figure 4 shows a typical assembly for a multi-shot magnetic tool. FIGURE 4 Magnetic tools measure azimuth based on the earth's magnetic field. Consequently, they measure magnetic, rather than true north, and we have to correct for this difference, or declination, when we report these measurements (Figure 5, The earth's magnetic field and Figure 6, Declination, magnetic to true north). FIGURE 5 FIGURE 6 Gyroscopic Survey Tools (adsbygoogle = window.adsbygoogle || []).push({}); Gyroscopic survey tools, like magnetic devices, are used to measure inclination, azimuth and tool orientation. The primary difference is the use of a gyroscopic compass, which maintains a fixed reference direction and measures relative changes in direction at selected depths with the aid of a timer and a motion sensor. Thus, unlike a magnetic survey tool, it can measure azimuth without using the Earth's natural lines of magnetic force. This makes it suitable for surveying wells where casing has been set or where there is magnetic interference from nearby wellbores. Gyroscopic tools also contain drift-recording instruments for measuring wellbore inclination. Like magnetic instruments, gyroscopic tools can have single or multi-shot capabilities, and many devices have electronic, computer-aided data recording and processing capabilities, along with continuous survey, surface readout features. They are not as rugged as magnetic tools, however, and so must be run on wireline. Although gyroscopes are not subject to magnetic interference, they are sensitive to drift caused by the earth's rotation and are affected by the position of the wellbore on the earth's surface. With conventional instruments, it is therefore necessary to optically orient the gyroscope on surface, and then to make several check shots when running in the hole. Bourgoyne et al (1991) describe this orientation procedure. "North-seeking" gyroscopic tools employ rate-gyroscopes and accelerometers to measure the earth's rotation rate and gravitational force at each survey station. This eliminates the need for optical surface alignments and pre-survey drift checks, improving both survey time and accuracy. Such tools are particularly useful for surveying through pipe in deep wells, and in situations that require a high degree of survey accuracy. Gyroscopic survey systems have one overriding limitation in horizontal and high-angle directional drilling, in that they cannot be run at inclination angles of greater than 70°. The inertial guidance systems long employed in aircraft navigation are also applicable to directional well surveying. An inertial navigation system is a position measurement tool, which determines a moving body's position in three dimensions by mathematically integrating the measured components of its acceleration. Unlike conventional directional surveys, which calculate position based on measurements of inclination and azimuth angles, inertial systems provide a direct means of measurement. Inertial navigation systems are fast, extremely accurate, and relatively independent of hole inclination and position on the earth. They are particularly useful in high latitude, high-angle wells such as those drilled in the North Sea (Baker-Hughes Inteq, 1993). Steering Tools (adsbygoogle = window.adsbygoogle || []).push({}); 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. 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). (adsbygoogle = window.adsbygoogle || []).push({}); Wireline Steering Systems (adsbygoogle = window.adsbygoogle || []).push({}); A wireline steering system consists of a bottomhole assembly that accommodates a measurement probe run on wireline (Figure 1). 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. FIGURE 1 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. MWD and LWD Systems https://youtu.be/hPe3_Y3ZO9Y (adsbygoogle = window.adsbygoogle || []).push({}); One 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. MWD and LWD systems make it possible to monitor and control operations even as drilling is taking place, by allowing operators to: Measure drill bit position and trajectory, Monitor penetration rate, actual weight-on-bit, downhole torque and drag, vibration and other drilling parameters, Compute pore pressures and get an early warning of potential overpressured zones, Detect and correlate geologic markers and formation tops, Evaluate formations even as they are being drilled. Systems are modular in design, and can be run with various sensor combinations to fit the requirements of the well plan. Figure 1 is a schematic diagram of an MWD/LWD system, FIGURE 1 while Figure 2 shows typical system configurations in various bottomhole assemblies. FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); MWD 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 (Figure 3, Mud pulse telemetry). These pulses are converted into electronic signals, which are processed and displayed at the surface. FIGURE 3 The basic components of the MWD instrument package include: a battery-powered pulser module, which in this case employs a continuous mud wave transmission a sensor module containing tri-axial inclinometers to measure drift and tri-axial magnetometers to measure azimuth, along with temperature and pressure sensors an electronics module. The MWD tool assembly shown in Figure 4 is run inside standard non-magnetic drill collars. FIGURE 4 LWD tools operate on basically the same principles as conventional wireline logging tools. The dual resistivity shown in Figure 5 (Individual MWD and LWD tools) contains a gamma ray tool, and two sets of transmitters and receivers to provide shallow and deep resistivity readings. FIGURE 5 The compensated density-neutron tool measures density and neutron porosity in a manner similar to that of analogous wireline tools. When drilling with a mud motor, these particular tools are run above the motor assembly--in other words, about 30 or 40 feet above the bit. In some applications, such as drilling in very thin, dipping pay zones, even this small "information gap" between the bit and the tool could lead to problems. For this reason, systems are available that allow "at-the-bit" measurements to be taken within a few feet of bottom. Although LWD tools work in generally the same manner as conventional logging tools, tool responses will most likely differ between highly deviated wells and vertical wells. These responses require special methods of interpretation. (adsbygoogle = window.adsbygoogle || []).push({}); EMWD Systems (adsbygoogle = window.adsbygoogle || []).push({}); Conventional 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. Figure 1 depicts EMI telemetry through a formation. FIGURE 1 Applications of this type of EMI are limited by depth, high resistance formations, anhydrite beds, and battery life. Deep wells require longer antennas and repeaters installed. High resistance formations require special antenna placement. Anhydrite beds cause signal complications due to reasons not well known, such as fractures. Battery life is still a limitation for long-time operations. (adsbygoogle = window.adsbygoogle || []).push({}); Figure 2 illustrates a Sperry-Sun Mercury (EMI) system, which relies on EMI telemetry through the drill string to derive better quality signals in deep wells. FIGURE 2 Tool specifications are shown below: Sperry Sun Mercury EMI Tool Specifications: Tool Length: 34 ft Tool outside diameters: 3.50 in, 4.75 in, 6.50 inch, 8.00 in., 9.50 in. Maximum pressure: 18,000 psi Maximum temperature: 125°C [257°F] Azimuth accuracy: +/- 1.75° Inclination accuracy: +/- 0.1° Pressure accuracy: +- 15 psi Power/Life: Lithium batteries / 140 hrs Maximum flow rate; Maximum Dogleg (Rotating/Sliding) 3.50 in: 250 GPM; 35/15 4.75 in: 350 GPM; 35/14 6.50 in: 650 GPM; 35/14 8.00 in: 950 GPM; 14/8 9.50 in: 1200 GPM; 14/8 Transmission rate (channel dependent): TF: 15-20 seconds PWD: 15-45 seconds TF/Gamma: 15-20 seconds Survey: 40-220 seconds (adsbygoogle = window.adsbygoogle || []).push({}); Well Trajectory Calculations (adsbygoogle = window.adsbygoogle || []).push({}); Permanent records of hole locations, and the accuracy of these records, can have significant impact on future drilling and completion operations, as well as on other technical, economic and legal issues relating to a field. To describe the well trajectory, we must be able to determine the coordinates xi, yi and zi from the measured angles θi and αi at every station i along the well path. There are several calculation methods available, including the following: Tangential method Balanced tangential method Minimum curvature method Radius of curvature method Angle-averaging method The tangential method is the least accurate of all methods, and should not be used. The most accurate are the radius of curvature and minimum curvature methods. In this section, we summarize the equations representing the minimum curvature, radius of curvature and angle-averaging methods. Minimum Curvature Method The minimum curvature method uses the angles measured at two consecutive stations, i−1 and i, to describe a smooth, circular curve that represents the wellbore path. It uses a dog-leg severity ratio factor, Rei, for each corresponding section of the curve. The coordinates xi and yi represent, respectively, the departures in the west-east and north-south directions, while zi is the vertical departure. These coordinates are expressed as follows: West-east departure: [latex]x_{i}= \dfrac{\Delta d_{i}}{2}\cdot \left ( \sin \theta_{i-1}\cdot \sin \alpha_{i-1} +\sin\theta_{i}\cdot \sin \alpha_{i} \right )\cdot R_{ei}[/latex] (1) North-south departure: [latex]y_{i}= \dfrac{\Delta d_{i}}{2}\cdot \left ( \sin \theta_{i-1}\cdot \cos \alpha_{i-1} +\sin\theta_{i}\cdot \cos \alpha_{i} \right )\cdot R_{ei}[/latex] (2) Vertical departure: [latex]z_{i} = \dfrac{\dfrac{\left ( \Delta d_{i} \right )}{2}}{\left ( \cos\theta_{i-1} +\cos\theta_{i} \right )\cdot R_{ei}}[/latex] (3) where (adsbygoogle = window.adsbygoogle || []).push({}); [latex]R_{ei}= \dfrac{2}{e_{i}}\cdot \tan \dfrac{e_{i}}{2}[/latex] (4) ei = angle change of drill string between i and i−1, given by [latex]e_{i}= \cos^{-1}\left [ \sin\theta_{i}\cdot \sin\theta _{i-1}\cdot \cos\left ( \alpha_{i}-\alpha_{i-1} \right )+\cos\theta _{i}\cos\cdot \theta _{i-1} \right ][/latex] (5) We can determine the coordinates at the nth point along the well path by algebraically summing over the total number (n) of survey points: [latex]x_{n}= \sum\limits_{i= 1}^{n}x_{i}[/latex] (6) [latex]y_{n}= \sum\limits_{i= 1}^{n}y_{i}[/latex] (7) [latex]z_{n}= \sum\limits_{i= 1}^{n}z_{i}+\left ( \textrm{Kick - off depth }\right )[/latex] (8) Radius of Curvature Method Like the minimum curvature method, radius of curvature assumes that the wellbore is a smooth curve represented by circular or spherical segments. From survey data at two consecutive stations, i−1 and i, we can determine the coordinates xi, yi and zi from the following equations: [latex]x_{i} = \dfrac{180\cdot \Delta d_{i}}{\pi \cdot \left ( \theta_{i}-\theta _{i-1}\right )\cdot \left ( \alpha_{i}-\alpha _{i-1}\right )}\cdot \left (\cos \theta_{i-1}-\cos\theta_{i} \right )\cdot \left ( \cos\alpha_{i-1}-\cos \alpha_{i} \right )[/latex] (9) [latex]y_{i} = \dfrac{180\cdot \Delta d_{i}}{\pi \cdot \left ( \theta_{i}-\theta _{i-1}\right )\cdot \left ( \alpha_{i}-\alpha _{i-1}\right )}\cdot \left (\cos \theta_{i-1}-\cos\theta_{i} \right )\cdot \left ( \sin \alpha_{i}-\sin \alpha_{i-1} \right )[/latex] (10) [latex]z_{i}= \dfrac{180 \cdot \Delta d_{i}}{\pi \cdot \left ( \theta _{i}-\theta_{i-1} \right )} \cdot \left ( \sin \theta _{i}-\sin \theta _{i-1} \right )[/latex] (11) where θi≠θi−1 and αi≠αi−1 Angle Averaging Method The angle averaging method takes the mean of two measured sets of inclination and azimuth values [(θi, αi) and (θi−1, αi−1)], and assumes that the wellbore follows a tangential path. The coordinates at station i are given by [latex]x_{i}= \Delta d_{i}\cdot \sin \dfrac{\theta_{i}+\theta_{i-1}}{2}\cdot \cos \dfrac{\alpha_{i}+\alpha_{i-1}}{2}[/latex] (12) [latex]y_{i}= \Delta d_{i}\cdot \sin \dfrac{\theta_{i}+\theta_{i-1}}{2}\cdot \sin \dfrac{\alpha_{i}+\alpha_{i-1}}{2}[/latex] (13) [latex]z_{i}= \Delta d_{i}\cdot \cos \dfrac{\theta_{i}+\theta_{i+1}}{2}[/latex] (14) We may use Equations 6, 7 and 8 above to calculate the total departures. (adsbygoogle = window.adsbygoogle || []).push({}); Geologic Steering https://youtu.be/Yg2C2RlgPn8 (adsbygoogle = window.adsbygoogle || []).push({}); In many drilling programs, it is easy to distinguish between planning the well trajectory and actually following it. The directional profile is clearly defined in the well plan, and then the well is drilled more or less along this pre-assigned course - a process known as geometric steering. Geometric steering served the industry for many years, and remains an important aspect of directional drilling. With a bent-housing positive displacement motor, a well-designed bottomhole assembly, and MWD capabilities, it is possible to minimize wellbore deviation and follow a planned course simply by changing the tool face orientation as needed. But even the most precise geometric steering capabilities may not be adequate to reach some pay zones. Many horizontal and extended-reach wells target small, thin, heterogeneous, highly fractured or steeply dipping reservoirs. Such reservoirs are all too easy to miss - a pre-assigned trajectory that is even a few feet too shallow, too deep or too far to the right or left can result in an unsuccessful well. Fortunately, there is an alternative approach to reaching difficult drilling targets and maximizing reservoir exposure: a process known as Geologic steering, or geosteering. Geologic steering combines directional drilling technology with geological and geophysical information and real-time formation evaluation capabilities to guide wells as they approach prospective pay zones, to stay within target intervals, to avoid zone boundaries or fluid contacts and to execute successful well completions. Figure 1, for example, depicts a horizontal well drilled in the North Sea to exploit a thin oil column below a gas cap. (adsbygoogle = window.adsbygoogle || []).push({}); FIGURE 1 Based on extensive reservoir simulation studies, the well's target was the oil-water contact. Using real-time resistivity data, the bit was steered up or down as needed, and the well was maintained at the desired position. (For more information on geologic steering tools and methods, refer to the topic Geosteering: Fundamentals, Planning and Implementation, which may be found in the Geology and Drilling). (adsbygoogle = window.adsbygoogle || []).push({}); Azimuth Change (adsbygoogle = window.adsbygoogle || []).push({}); When there is a need to change the azimuth of the well course - for instance, as a result of an over optimistic trajectory setting, unforeseen events, or errors in estimating natural deviation tendencies—the first steps are to determine the required change based on an initial feasibility study, and to determine the orientation of the tool face. To reset the toolface properly, the directional driller must have certain information: The present inclination and azimuth of the hole. The required change in inclination or azimuth to correct the trajectory or kick off the well. The expected rate of change (i.e., the dog-leg) that the deflecting tool can provide. A large change in azimuth is easier when the inclination is small. If the inclination is greater than 30 degrees, and the planned azimuth correction is greater than 15 degrees, it is best to change azimuth as soon as possible (for instance on the first bit replacement), especially if the inclination has not reached its maximum value. A rule of thumb gives [latex]dA = \frac{180}{L}[/latex] Where L = present inclination and dA = possible change in azimuth per 100 ft drilled with constant inclination. Azimuth changes can be determined using any of three methods (Byrum, 1982; Short, 1993). Ragland diagram. "Ouija Board" nomograph. Direct calculations. The main consideration for the directional manager is to avoid being faced with the impossibility of reaching the target. Graphic construction helps to solve the problems associated with a hurried, last-minute decision. Ragland Diagram (adsbygoogle = window.adsbygoogle || []).push({}); The Ragland Diagram is comprised of four elements (Figure 1): A line OA indicating the initial azimuth of the wellbore, and marked off in increments of inclination from vertical. A dogleg circle with its center at the present angle of inclination (α1) and its radius equal to the dog-leg angle (DL). A line AB indicating the orientation of the deflection tool with respect to the current azimuth OA. A line OB indicating the direction obtained with respect to the original direction. Where L = present inclination and dA = possible change in azimuth per 100 ft drilled with constant inclination. Azimuth changes can be determined using any of three methods (Byrum, 1982; Short, 1993). Ragland diagram. "Ouija Board" nomograph. Direct calculations. The main consideration for the directional manager is to avoid being faced with the impossibility of reaching the target. Graphic construction helps to solve the problems associated with a hurried, last-minute decision. Ragland Diagram The Ragland Diagram is comprised of four elements (Figure 1): A line OA indicating the initial azimuth of the wellbore, and marked off in increments of inclination from vertical. A dogleg circle with its center at the present angle of inclination (α1) and its radius equal to the dog-leg angle (DL). A line AB indicating the orientation of the deflection tool with respect to the current azimuth OA. A line OB indicating the direction obtained with respect to the original direction. FIGURE 1 Suppose that we have drilled to point O, with an inclination α1 of 4 degrees at an azimuth of N 40°E. We want to know what toolface orientation is needed to direct the well course to a new azimuth (α2) of N 55 °E, within the constraint of DL = 2 degrees. We would begin by drawing a line from O at an angle of (40°+15°), or N 55° E. Next, we would draw a circle, with its center at α1, having a radius corresponding to DL. We would then draw a line from A to B and measure its angle to determine the required toolface setting (TF), which in this instance is 45°. Thus, for these parameters - TF, DL and α2 - if any two of them are known, we can determine the one that is unknown. (adsbygoogle = window.adsbygoogle || []).push({}); An established method that is used as a standard on every drilling site is to use a Ragland diagram right from the start of the build up phase, and to continuously analyze the Ragland diagram and the result of successive plots. This keeps the driller aware of the efficiency of the bent sub/downhole motor combination (i.e., the angle change gradient and the roll-off of the downhole motor) for predetermined weight-on-bit and flow rate conditions. The driller can then orient the tool face without hesitation, avoid errors, and by increasing inclination, reach the desired azimuth with minimal difficulty. Using a Ragland diagram helps to determine: The azimuth and inclination resulting form a deflected hole, in accordance with the initial orientation of the deflection tool. The roll-off of a deflection tool. The orientation to be given to a downhole motor, knowing its roll-off and the real dog-leg created by the downhole motor / bent sub combination with NDMC (non-magnetic drill collar) of a certain size. The total dog-leg between two surveys in order to determine the API dog-leg calculated over a distance of 100 ft. Ouija Board The Ouija board involves a similar technique to that described for the Ragland diagram, but it is much quicker since no diagram needs to be drawn. In Figure 2, β corresponds to the overall angle change over the drilled interval (i.e., DL), while γ represents the tool face orientation (TF). The current and new inclination angles (α and αN, respectively), as well as the change in azimuth (Δε) are known. FIGURE 2 Direct Calculation As an alternative to the graphical methods describe above, a series of equations can be derived to calculate the necessary angles directly. To calculate the change in azimuth in a given toolface hading , dog-leg angle and inclination [latex]\Delta \beta = \tan ^{-1}\left ( \dfrac{\tan DL\ \cdot \ \sin TF}{\sin \alpha _{1}+\tan DL\ \cdot \ \cos \alpha _{1}\ \cdot \ \cos TF} \right)[/latex] where (adsbygoogle = window.adsbygoogle || []).push({}); Δβ = change in azimuth DL = dog-leg angle TF = toolface setting α1 = present inclination. The new inclination angle can be given by [latex]\alpha_{2}=\cos^{-1}\left ( \cos \alpha _{1}\cdot \cos DL -\tan DL \cdot \sin \alpha _{1} \cdot \sin DL \cdot \cos TF \right )[/latex] o calculate the toolface heading from the dog-leg angle and the expected change in inclination, the following equation can be used: [latex]TF = \cos^{-1}\left ( \dfrac{\cos \alpha _{1}+\cos DL-\cos\alpha _{2}}{\sin \alpha _{1}\ \cdot \ \sin DL} \right )[/latex] Once the required toolface setting has been determined, the effect of reactive torque must be considered in re-orienting the toolface. Reactive torque is the twisting effect caused by the stator of the downhole motor turning anticlockwise in response to the rotor turning clockwise. Most manufacturers provide tables with estimates of how much left-hand turn can be expected under certain conditions. From these tables or from experience, the directional driller must compensate for reactive torque be pointing the toolface to the right of the calculated heading. As soon as the bit begins to drill, the scribe line will turn to the left to bring it back to the calculated heading. (adsbygoogle = window.adsbygoogle || []).push({}); Exercise Directional Drilling Tools (adsbygoogle = window.adsbygoogle || []).push({}); 1. Describe what general well pattern (Build-and-hold, Build-hold-and-drop, Continuous build, or Build-hold-and-build) you would employ to reach and produce the following target intervals: (a) a thin carbonate reservoir with low matrix permeability and an extensive vertical fracture network. (b) an oil-producing sandstone at a vertical depth of 5000 ft, located 800 ft southwest of the surface rig location. (c) an oil zone underlying a large salt dome; surface location lies to the west of the salt dome. Solution (a) In a thin carbonate reservoir with low matrix permeability and an extensive vertical fracture network, the objective would be to intersect the fractures. Therefore, a wellbore perpendicular to the fracture network would be the best choice. Select the build-hold-and-build (horizontal) pattern. (b) The target zone is located at a moderate depth, with a significant but not extended horizontal departure. Although the surface casing point is not specified, a good first choice would be to begin deflection below the surface casing and gradually build angle to total depth. Select the build-and-hold pattern. (c) The best course would be to avoid the salt dome if possible. Drill the well vertically past the salt dome, then initiate a deep deflection to reach the oil zone. Select the continuous build pattern. Assessment Directional Drilling Tools (adsbygoogle = window.adsbygoogle || []).push({}); 1. What information does the directional driller NOT need in order to reset the toolface and correct a well's trajectory? A .Present inclination and azimuth of the holeB .True vertical depth of the well ✔C .Required change in inclination or azimuthD .Rate of change (dog-leg) that the deflecting tool can provide 2. Which of the following is NOT an MWD component? A .Pulser moduleB .Sensor moduleC .Electronics moduleD .Inertial guidance system ✔ 3. Generally the _______ a well's target diameter or radius, the higher the drilling cost. A .largerB .smaller ✔C .Neither of the above; target radius is unrelated to drilling cost. 4. In what type of formation might you consider using a jet bits with orienting nozzles to initiate wellbore deflection? A .Fractured limestoneB .Soft shale ✔C .Medium-to-hard sandstone 5. In which of these bottomhole assembly configurations would you NOT place a stabilizer directly above the bit? A .Angle-building assemblyB .Angle-dropping assembly ✔C .Angle-holding (packed hole) assembly 6. Considerations that are unique to controlled directional drilling include: A .Trajectory planningB .Optimizing weight on bitC .Optimizing hydraulicsD .Use of downhole motorsE .A and D ✔F .B and C (adsbygoogle = window.adsbygoogle || []).push({}); 7. Which of the following well trajectories is particularly well suited for salt dome drilling? A .Build and holdB .Continuous build ✔C .Build, hold and dropD .Build, hold and build 8. What advantage does a rotary steerable system offer over a mud motor working in the "sliding" mode? A .Improved hydraulic performanceB .Reduced friction and dragC .Better weight transferD .A, B and C ✔E .A and B only 9. What type of survey tool would you run inside a cased hole? A .MagneticB .Gyroscopic ✔C .Either A or BD .Cannot run survey tools in cased hole. 10. Which of the following is the most accurate method of describing the well trajectory? A .Tangential methodB .Angle-averaging methodC .Radius of curvature method ✔D .Balanced tangential method 11. Which of these developments has made it possible to advance from geometric to geologic steering of well trajectories? A .Bent-housing mud motorsB .MWD toolsC .Real-time formation evaluation capabilities ✔ 12. Which of these statements about downhole mud motors is FALSE? A .The use of a downhole motor tends to increase the rig's power requirements. ✔B .Downhole motors are used both for directional drilling and for controlling deviation in crooked hole formations.C .The rotor in a positive displacement motor is turned by the action of the circulating drilling fluid.D .Turbine motors have narrower operating ranges than positive displacement motors. 13. When describing the well trajectory, the method that requires the use of a dog-leg severity ratio factor is the: A .Tangential methodB .Minimum curvature method ✔C .Radius of curvature methodD .Angle averaging method 14. A wireline steering system uses _________ to measure direction and hole angle. A .magnetometersB .accelerometersC .A and B ✔ 15. A mechanical drift indicator provides a measurement of _________. A .inclination from vertical ✔B .azimuthC .A and B 16. Which of these directional parameters is measured in the vertical plane? A .build rate angle ✔B .turn rate angleC .lead angle 17. What types of formations causes signal complications for EMWD systems? A .Sandstones containing high-salinity waterB .ShalesC .Anhydrites ✔D .A and B only 18. Conventional MWD and LWD systems work in what type(s) of drilling fluid(s)? A .Incompressible (i.e., continuous liquid phase) ✔B .Compressible (i.e., air, gas or foam)C .A and B Recommended for You (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Overview Deviation in Vertical Wells Case Study of Geosteering (adsbygoogle = window.adsbygoogle || []).push({});