Bottomhole Assembly Tools

(adsbygoogle = window.adsbygoogle || []).push({}); Bottomhole Assembly (BHA) Components consist of varying tool types from: Stabilizers https://youtu.be/lw7uV7CFpws Stabilizers, by centralizing the drill string at selected points in the borehole, perform these important functions: They ensure that the weight of the drill collars is concentrated on the bit. They reduce torque and bending stresses in the drill string. They prevent wall-sticking or key-seating of the drill collars. They can be used to build, drop or maintain hole angle in directional drilling, and maintain constant bit direction in straight-hole drilling. The type and placement of stabilizers in the drill string depends on local drilling conditions and well objectives. In areas with a tendency toward crooked drilling, the stabilizer(s) immediately above the bit must have adequate wall contact to provide bit stability and guidance. The stabilizer(s) must also have wear properties that permit them to stay in gauge for the life of the bit, and they must be able to centralize the drill string without digging into the borehole wall. In an angle-holding, or packed-hole assembly, which requires maximum stiffness to "lock in" the direction of the drill string, the stabilizers should have the largest possible cross-sectional area that will permit adequate circulation passage. For packed-hole drilling techniques, stabilizers act like drill bushings to minimize drift and hole angle change by centering the drill string. When utilizing a pendulum, or angle-dropping assembly, stabilizers are frequently used to increase the effectiveness of pendulum by proper stabilizer placement and/or a reduction in gauge diameter. They similarly serve to increase the effectiveness of an angle-building assembly by allowing a ‘’belly’’ or sag in the collars between stabilizers . Stabilizers are also designed to prevent wall-sticking of the drill collars and to guide them out of key seats. Stabilizer Types (adsbygoogle = window.adsbygoogle || []).push({}); There are a variety of stabilizer types available for different drilling environments, the most common of which are: Integral blade stabilizers Replaceable sleeve stabilizers Replaceable wear pad stabilizers Non-rotating sleeve stabilizers Welded blade stabilizers. These stabilizers types are designed either for bottomhole configuration (pin up/box down with proper API fishing neck, to be run just above the bit), or string configuration (box up/ pin down, to be run at various points in the drill string). Integral Blade Stabilizer The integral blade stabilizer(Figure 1: Integral Blade Stabilizer) can be used in all degrees of formation hardness, but is specifically designed for harder formations to lessen the risk of moving replaceable or welded-on components. Its long ribs are designed to provide the wall contact necessary for proper stabilization, and are contoured to minimize torque while drilling. FIGURE 1 For larger hole sizes, the integral blade stabilizer can be manufactured with a shop-replaceable sleeve. Its long ribs are milled directly on the sleeve to provide unitized construction, thus preventing loss of ribs in the hole as sometimes happens with welded rib stabilizers. These stabilizers can be provided with pressed-in tungsten-carbide compacts or welded-on hardfacing on the wear surfaces to increase gauge life. Integral blade stabilizers are available in both string and bottom hole types. Integrated blade stabilizers are more expensive due to the fact that the outside diameter cannot be restored. Replaceable Sleeve Stabilizer The replaceable steel sleeve stabilizer (Figure 2) can be used in all degrees of formation hardness, but is specifically designed for harder formations to lessen the risk of moving or welded-on components. Its long ribs are designed to provide the wall contact necessary for proper stabilization, and are contoured to minimize torque while drilling. FIGURE 2 Sleeves can be changed in the rotary table, making this stabilizer type economical for remote locations. Replaceable sleeve stabilizers are available both in bottomhole and string configuration. They can be used for more than one hole size by changing sleeve size. Deep-grooved passages between the sleeve ribs assure adequate circulation past the tool. Replaceable Wear Pad Stabilizer (adsbygoogle = window.adsbygoogle || []).push({}); The replaceable wear pad stabilizer, with rig-replaceable wear pads, is very effective for packed-hole assemblies, and can be used in all types of formations. Figure 3 shows a replaceable wear pad string stabilizer, while Figure 4 shows a bottomhole configuration. FIGURE 3 FIGURE 4 The wear pads, which can easily be changed out in the rotary table with hand tools, provide long wall contact area, and pressed-in tungsten carbide and carburized wear surfaces provide maximum downhole life. Within limits, changing wear pads permits body use in more than one hole size (Figure 5). FIGURE 5 Built-in wear indicators are available to indicate the need for replacement before body damage occurs. The stabilizer body has a fluted configuration to provide for adequate circulation. This stabilizer type is available in either bottomhole or string configuration, so that two or three tools can be run in tandem hookups to provide additional wall contact as required. Non-Rotating Sleeve Stabilizer (adsbygoogle = window.adsbygoogle || []).push({}); The non-rotating sleeve stabilizer (Figure 6: Non-rotating rubber-ribbed stabilizer. is one of the most effective stabilizer types. FIGURE 6 A true "drill bushing," it can be used in hard to medium-hard non-abrasive formations, since the sleeve does not rotate or dig into the borehole wall. The one-piece, rig-replaceable sleeve is molded over a mild steel inner bushing to prevent it from being lost downhole, and has fluted marine-type inner bearings, designed to allow continuous cleaning by the circulating fluid. Drilling fluid acts as a lubricant and coolant to avoid friction between the mandrel and the non-rotating sleeve. The non-rotating sleeve stabilizer is always a string-type tool. Welded Blade Stabilizer The welded blade stabilizer(Figure 7) is designed to centralize drill collars and provide better borehole alignment. FIGURE 7 Its rotating blade is especially effective in soft formations, where balling-up of mud and cuttings on the drill string can cause problems. (adsbygoogle = window.adsbygoogle || []).push({}); Drilling Jars https://youtu.be/29rHJQAIEcg (adsbygoogle = window.adsbygoogle || []).push({}); A jar is a mandrel which slides within a sleeve. The free end of the mandrel is shaped in the form of a hammer to provide a striking action against the face of the anvil. In well operations, jars are used to provide quick, sharp, upward or downward motion to free stuck pipe. Although we most commonly associate them with fishing operations, they can also be run on drilling bottomhole assemblies as a precautionary measure. Drilling jars are especially appropriate for drilling in sticky, heaving, sloughing or crooked holes. They also have applications in controlled-weight directional drilling, as well as in coring operations. Figure 1 shows a mechanical rotary drilling jar. FIGURE 1 Jars are usually identified according to type, inside and outside diameter, thread connection and stroke length. There are a number of jar types available, and the type of jarring action utilized will depend on the jar being used and the specific operating conditions. For typical mechanical or hydraulic jars, upward or downward motion is initiated by pulling up or slacking off on the drill string until a pre-set triggering load is reached, initiating a sharp blow. A few such blows may be sufficient to free a stuck drill string without the expense and risk of a fishing job. Hydraulic jars use a hydraulic fluid to control the firing of the jar until the driller can apply the appropriate load to the string to give a high impact. This controlled action (delay) is provided by hydraulic fluid which is forced through a small port or series of jets. Hydraulic jar firing delay is dependent upon the combination of load and time. Hence hydraulic jars are adjustable according to the downhole over-pull. In drilling operations, jars are generally run high in the drill collar string, with some drill collars above them. Optimum jar placement and triggering load, along with the need to enhance the jarring impact by running a companion tool known as a jar accelerator, is best determined individually for each bottomhole assembly, with input from the service company providing the tools. In general, an increase in jar stroke length increases the jarring effect. With these obvious advantages, a long stroke hydraulic jar is preferable to a mechanical jar. (adsbygoogle = window.adsbygoogle || []).push({}); Two phenomena have to be considered when jarring: the impact force and the impulse of the jarring action. The impact force must be high enough to break the binding force causing the pipe to stick. It must also act long enough to move the pipe this is what is termed the impulse. Both the impact force and the impulse are influenced by the number of drill collars located above the jar. The smaller the quantity of drill collars, the higher the impact force. Conversely, the larger the number of drill collars the greater the impulse force. A compromise has to be reached where both impact and impulse are working together to free the pipe. The jars should be run in tension wherever possible. This is mandatory for mechanical jars, and while hydraulic jar manufacturers state that their jars can be run in compression, this is not advisable because applied weight on bit can lead to inadvertent cocking of the jar. For vertical wells, the amount of drill collars to be run below the jar should be the sufficient to allow the required bit weight and place the neutral point at least 30 feet away from the jar. The buoyed weight method should be used to calculate the required length and a 15% safety factor added. For directional wells, an additional safety factor should be applied to the buoyed weight of the collars to account for frictional drag of the string against the low side of the hole. (adsbygoogle = window.adsbygoogle || []).push({}); Reamers https://youtu.be/0-ma1vCFK6Y (adsbygoogle = window.adsbygoogle || []).push({}); In hard or abrasive formations, the outside cutting structure of a bit gradually wears away if it is not protected. The bit becomes "pinched" or undergauge, resulting in a hole diameter that becomes smaller with increasing depth. Figure 1 shows an extreme example of an under-gauge bit — this 6 1/2′′ bit, with no stabilization, wore down to 3 3/4′′ OD after making 428 ft in 59 3/4′′ hours. FIGURE 1 When a hole is severely undergauge, it is necessary to ream each new bit back to bottom before drilling can resume. This not only costs rig time and reduces bit life, but it increases the possibility of sticking the drill string. Roller-cutter rotary reamers, with either three points or six points of wall contact (Figure 2 and Figure 3), have proven to be effective for keeping holes in gauge. FIGURE 2 This not only prolongs bit life, but it also minimizes wear on other tools used in packed-hole assemblies in crooked hole drilling areas. Three-point bottomhole reamers are designed to be run between the bit and the drill collars, with the spacing from the bit to the reamer kept to a minimum. This set-up keeps the hole in gauge to ensure minimum time spent reaming back to bottom, protects the gauge of tools above the reamer and provides some stabilization to the bit. (adsbygoogle = window.adsbygoogle || []).push({}); Three-point string rotary reamers are sometimes run in the drill collar or drill pipe strings to centralize the strings in crooked hole areas. When run above the drill collars, they can be effective in reaming out dog-legs, key-seats and ledges. Both types of three-point reamers contain wall contact points spaced 120° apart. Six-point bottomhole reamers are run between the bit and drill collars, and are used when greater reaming capacity is required than can be provided by the three-point design. They are especially effective in hard, abrasive formations where extremely hard cutters can be run in the lower points and regular hard cutters in the upper points. The six points of contact, spaced 60 °C apart, provide better stabilization than a three-point reamer in crooked hole areas. A variety of roller reamer cutters are available for different formation types. For hard formations that require a scraping action, such as dolomite, hard lime and chert, the "Q" cutter (Figure 3, top) may be used. For extremely hard formations, the "K," or knobby cutter (Figure 3, bottom) may be used. Its tungsten carbide compacts act as teeth to fracture the formation. FIGURE 3 The reamer bodies shown here utilize drive-fit hardened reamer pins and bearing blocks, which can be easily replaced at the wellsite without the need for special tools or welding. (adsbygoogle = window.adsbygoogle || []).push({}); Hole Openers (adsbygoogle = window.adsbygoogle || []).push({}); A hole–opener (Figure 1: Full-diameter hole opener) is designed to enlarge the diameter of a previously or simultaneously drilled smaller borehole. FIGURE 1 Three situations (at least) are possible (Sampaio, 2007): To drill the borehole section with a smaller bit, and later to enlarge to the final diameter. In this case, a special tool called bull nose is connected in the place of the bit, to guide the hole opener along the pre-drilled hole. To drill the borehole section with a smaller bit and simultaneously enlarge to the final diameter. To enlarge a section below a casing with a diameter larger than the internal diameter of the casing. In this case, a special hole opener known as an underreamer, with hinged arms actuated hydraulically, is used—the drilling fluid pressure actuates in rams that open the arms, forcing the cutters against the borehole wall. Float Subs (adsbygoogle = window.adsbygoogle || []).push({}); A float sub, which is usually run just above the bit, contains a check valve (Figure 2: Drill pipe float valve). Its purpose is to prevent drilling fluid from backflowing into the drill string. Such backflow could occur, for example, in the top section of the hole when large volumes of cuttings are produced at high rates of penetration, which might result in increased mud density and plugged bit nozzles. A float sub can also reduce the potential for kicks due to swabbing. When a float sub is placed above the bit, the drill string has to be filled while running in the hole. is designed to enlarge the diameter of a previously or simultaneously drilled smaller borehole. FIGURE 2 Circulating Subs A circulating sub is incorporated within the drill string (above the mud motor or MWD assembly) to provide a large opening to circulate through. A ball is dropped to close the downward path of the mud flow and open a side path that allows the mud to flow in straight to the annulus. A circulating sub is used when lost circulation material (LCM) is to be pumped, to avoid plugging the bit, MWD or mud motor. Circulation needs to be increased to clean the hole prior pulling out of the hole. (adsbygoogle = window.adsbygoogle || []).push({}); Crossover Subs https://youtu.be/xbC5q3gCIJo (adsbygoogle = window.adsbygoogle || []).push({}); Crossover subs join drill string components of different sizes or thread connections (Figure 1: Crossover Sub and Figure 2: Non-magnetic corssover sub). For example, a double-box crossover would be needed to join a bit with an API Regular pin connection to a drill collar with API Full Hole pin connection. It is important to keep track of the types of connections on each component of the drill string, and to make sure that the appropriate crossovers are available. FIGURE 1 FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); Vibration Dampeners https://youtu.be/ea9ZIL5p38M (adsbygoogle = window.adsbygoogle || []).push({}); One of the more important considerations in drill string design is dealing with the vibrations and shock loads that are produced as the bit rotates on bottom. Such vibrations can cause rough running at the surface, and can result in damage to the bit, drill collars, drill pipe and other components. There are a number of drilling parameters that determine whether vibration will occur, including: formation lithology (e.g., hard rock, broken formations, and formations with intermittent hard and soft streaks) depth; bottomhole assembly configuration; weight on bit rotary speed. Engineers can use these and other parameters during the well planning process to develop computer models for optimizing drill string design. They can also monitor vibrations during the drilling of the well by means of surface or downhole (MWD) sensors. It is often possible to control or eliminate downhole vibrations by modifying the bottomhole assembly configuration, or simply by adjusting rotary speed and/or weight on bit. A vibration dampener or shock sub may be useful in some cases for absorbing vibrations and shock loads. A vibration dampener is a type of shock absorber designed to prevent vibrations generated by the bit from traveling up the drill string to the surface. It is commonly run between the bit and the drill collars, or above the large-diameter short drill collar segment of a packed-hole drilling assembly. When properly used, vibration dampeners can result in faster drilling rates, longer bit life, less damage to the drill string and surface equipment, and reduced torsional impact. (adsbygoogle = window.adsbygoogle || []).push({}); In its simplest form, a shock sub consists of three parts: a grooved female housing, a matching splined male housing and a set of entrapped spring elements (Figure 1, Figure 2, and Figure 3). The spring and spline mechanisms are lubricated in hydraulic oil which is retained by seals between the housing and the mandrel. When installed above the bit, weight on bit tends to compress the springs and close the shock sub. The pressure drop through the bit nozzles below the tool tends to counteract this by acting against the internal cross section and pumping the tool open. In theory as the bit bounces and or the assembly vibrates the shock sub strokes rapidly up or down around a median point, minimizing fluctuations in WOB and isolating the bit and assembly from each other. Shock subs are used to minimize the effect of drillstring vibrations upon the bit to enhance bit performance and bit life. In addition the effects of bit bounce are reduced and isolated from the drillstring to reduce fatigue wear of the string. FIGURE 1 FIGURE 2 FIGURE 3 Because of the complexity and magnitude of the forces acting on the bit and drill string, vibration dampeners cannot be considered a cure-all for vibration problems. They should not be routinely added to drill strings without first modeling their effects. Improperly applied, a shock sub may not only fail to absorb severe vibrations, but could even create additional vibrations, thereby accelerating, rather than preventing, drill string failure. (adsbygoogle = window.adsbygoogle || []).push({}); Drill Strings for High-Angle Drilling (adsbygoogle = window.adsbygoogle || []).push({}); In high-angle drilling (Horizontal and extended-reach wells), getting the required weight to bottom is a primary requirement just as it is with vertical drilling operations, and torque, drag and buckling are critical design parameters. The approach to drill string design for high-angle wells is fundamentally different from that of vertical wells. The weight on bit (WOB) in high-angle drilling does not come from the weight of drill collars placed between bit and drill pipe as the case for vertical drilling. Instead, an "inverted" configuration is used consisting of, from top to bottom: A vertical section, made up of conventional drill pipe run in tension A weight stack section, consisting of drill collars or heavy wall drill pipe A build section, consisting of compressive service drill pipe (this is the section where maximum bending stress occurs) A horizontal load section, consisting of large-diameter or compressive service drill pipe —this section must transmit axial and torsional loads, and it is here that torque and drag are of primary concern and must be kept to a minimum. A bottomhole assembly consisting of a bit, downhole motor, subs, non-magnetic drill collars, MWD/LWD tools and rotary steerable systems. Assessment Bottomhole Assembly Tools (adsbygoogle = window.adsbygoogle || []).push({}); 1. Which of these functions is NOT performed by stabilizers? A .Ensure that weight of drill collars is concentrated on the bit.B .Provide a gradual change in stiffness between the drill collars and the drill pipe.C .Reduce torque and bending stresses in the drill string.D .Build, drop or maintain hole angle. 2. Welded blade stabilizers are particularly effective for use in: A .Hard formationsB .High-angle drillingC .Packed bottomhole assembliesD .Remote drilling locationsE .Soft formations 3. Which of these statements about drilling jars is FALSE? A .Jars are usually only run as part of a fishing assembly.B .In general, the smaller the number of drill collars run above a jar, the higher the impact force.C .In general, the larger the number of drill collars run above a jar, the higher the impulse force.D .Whenever possible, drilling jars should be run in tension. 4. Three-point string rotary reamers are particularly effective for: A .Reaming out dog-legs, key seats and ledgesB .Maintaining in-gauge wellbores in hard, abrasive formations.C .A and B 5. Hole openers can be designed to _____. A .enlarge previously drilled hole intervalsB .simultaneously enlarge hole intervals as they are being drilled with a smaller diameter bit.C .enlarge hole sections below casingD .A, B and CE .A and B only 6. Where is a float sub usually located in the bottomhole assembly? A .Near the top of the drill collars.B .Just above the bit.C .Above the MWD assembly. 7. In high-angle drilling, compressive service drill pipe is used in ___. A .the vertical section of the drill string.B .the build section of the drill string.C .the horizontal load section of the drill string.D .A, B and CE .B and C onlyF .A and C only Recommended for You (adsbygoogle = window.adsbygoogle || []).push({}); Drill Pipe Directional Drilling Overview Drill String and Bit Considerations in Deviated Wells Drill String Overview What is a Kelly in drilling? What is a Drill Collar? Underbalanced Drilling in Directional Wells (adsbygoogle = window.adsbygoogle || []).push({});