Drill Pipe

(adsbygoogle = window.adsbygoogle || []).push({}); Dimensions and Strengths https://youtu.be/-IoTMZDJQIg Like other oilfield tubulars, drill pipe comes in a variety of lengths, diameters, weights and grades of steel. Drill pipe is also specified according to its upset (the type of end section provided for weld-on connections or tool joints). Factors that influence drill pipe selection include: Hole size Well depth Casing and cementing requirements Subsurface pressures Circulating system and drilling mud parameters Hoisting capacity of drillng rig Pipe availability and rental cost Contract provisions The American Petroleum Institute has established standards for drill pipe manufacturing practices, dimensions, strengths and performance properties. These standards appear in the following publications: API Spec 5DP/ISO 11961: Specification for Drill Pipe API Bul 5C2: Bulletin on Performance Properties of Casing, Tubing and Drill Pipe API RP 7G: Recommended Practice for Drill Stem Design Operating Limits Size and Weight API-standard drill pipe is available in three length ranges: Range 1(18-22 ft) Range 2 (27-30 ft) Range 3 (38-45 ft). The most commonly used length is Range 2. Thus, the typical "average" length of a joint of drill pipe is about 30 feet, or just under 10 meters. Table 1 lists outside diameters and nominal weights for API standard drill pipe (note that these diameters and weights apply only to the drill pipe tube, and do not include the weights and diameters of tool joints and upsets). This information is available in API Spec 5DP and API RP 7G. Table 1: API Standard Drill Pipe Diameters and Weights Outside diameter, inches Nominal weights, lbft∗ \tfrac{lb}{ft}^* 2.875 10.40 3.5 9.50 13.30 15.50 4 14.00 4.5 13.75 16.60 20.00 5 16.25 19.50 25.60 5.5 21.90 24.70 6.625 25.20 27.70 Strength (adsbygoogle = window.adsbygoogle || []).push({}); The strength of a joint of drill pipe is defined in terms of : Pipe body yield strength: a measure of the pipe's resistance to axial tension Collapse resistance: a measure of the pipe's ability to withstand external pressure Internal yield pressure: a measure of the pipe's ability to withstand internal pressure. The values of these parameters depend on the grade of steel used to manufacture the pipe, and on the pipe's size and weight per unit length. Table 2 lists some of the standard grades of steel used in drill pipe, along with their minimum yield strengths, while Table 3 shows how drill pipe strength (Grade E in this case) varies with diameter and weight. GradeMinimum Yield, psiE75,000X-9595,000G-105105,000S-135135,000V-150150,000Table 2: API Standard Steel Drill Pipe Grades Table 3: Minimum Performance Properties of Grade E Drill Pipe (after API Bul 5C2) Outside diameter, in. Nominal weight, lbft \tfrac{lb}{ft} Collapse Resistance, psi Internal Yield Pressure, psi Pipe Body Yield Strength, lb 2.375 6.65 15,600 15,470 138,000 2.875 10.40 16,510 16,530 214,000 3.50 9.50 10,040 9520 194,000 13.30 14,110 13,800 276,000 15.50 16,770 16,840 323,000 4.00 11.85 8410 8600 231,000 14.00 11,350 10,830 285,000 4.50 13.75 7200 7900 270,000 16.60 10,390 9830 331,000 20.00 12,960 12,540 412,000 5.00 16.25 6970 7770 328,000 19.50 10,000 9500 396,000 5.50 21.90 8440 8610 437,000 24.70 10,460 9900 497,000 6.625 25.20 4810 6540 489,000 (adsbygoogle = window.adsbygoogle || []).push({}); Upsets https://youtu.be/7CNPNRemz38 (adsbygoogle = window.adsbygoogle || []).push({}); An upset - located at either end of a joint of drill pipe and to which is attached a threaded connection, or tool joint - is thicker than the rest of the drill pipe tube to provide for stronger welds. Drill pipe upsets can be either internal, external or internal-external. In an internal upset, extra wall thickness is added by decreasing the pipe's inside diameter at the upset area; the outside diameter does not change (Figure 1). FIGURE 1 In an external upset, extra wall thickness is added by increasing the pipe's outside diameter at the upset area; the inside diameter does not change (Figure 2). FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); In an internal-external upset, extra wall thickness is added by decreasing the pipe's inside diameter and increasing its outside diameter at the upset area (Figure 3). FIGURE 3 (adsbygoogle = window.adsbygoogle || []).push({}); Tool Joints https://youtu.be/CXDev2kw6v4 (adsbygoogle = window.adsbygoogle || []).push({}); Tool joints (Figure 1) are box-pin connections with rounded threads, which are fabricated separately from the drill pipe tube and then welded on at the upsets. FIGURE 1 A key consideration in tool joint design - both from the standpoint of tool joint makeup and rotational forces encountered during drilling - is torsional yield strength. Tool joint performance specifications therefore include information on torsional yield strength and on recommended makeup torque. The proper make-up torque for a tool joint is a function of its type, size, outside diameter, inside diameter and condition. API Standards for Tool Joints API RP 7G (1998) and API Spec 7-2/ISO 10424-2 (2008) list standards for various tool joint types, including: Internal flush (IF): includes NC26,* NC31, NC38, NC46 and NC50 connections Full hole (FH): includes NC40 connections Open hole (OH) Slim hole (SH): includes NC26, NC31 and NC38 connections Slim line (SL): H-90/PAC Wide open (WO): includes NC38, NC46 and NC5O connections "Xtra" hole (XH): includes NC46 and NC5O connections. * "NC" designate API Numbered Connection. These API connections were developed for incorporation into the old tool joint connection types, and for design of new connections. The number size is simply the size of the pitch diameter in inches at the gauge point of the threads rounded off to the first two digits with the decimal point removed. For example, the gauge point of the pin in Figure 2, measured 5/8′′ from the shoulder, is 5.616 inches giving a number size of 56. FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); Table 1 illustrates the differences between some of these basic tool joint types for the case of 4 1/4, 16.60 lb/ft, new Grade 95 drill pipe (API RP 7G). Table 1: Properties of New Tool Joints, 412 4\tfrac{1}{2} ′′ ^" , 16.60 lbft \tfrac{lb}{ft} , Grade 95 Drill Pipe Upset Tool Joint OD, inches ID, inches Tensile yield, lb Torsional yield, ft-lb Recommendedmake-up torque, ft-lb Internal-External 414′′ 4{\tfrac{1}{4}}'' FH 6.000 3.00 976,156 34,780 21,149 Internal-External NC46 6.250 3.25 1,084,426 39,659 16,997 Internal-External NC50 6.375 3.75 939,095 37,676 18,838 Internal-External 414 4\tfrac{1}{4} ′′ ^" H90 6.000 3.25 938,984 39,021 22,616 Tool joints also vary according to the number of threads per inch (ranging between 3 1/2 and 5 threads per inch, with most connections having 4 or 5 threads per inch), the amount of taper per foot and the overall length of the box and pin. Identification An examination of the tool joint connections listed above indicates that some of them are identical. For example, the NC 26 connection applies to both Internal Flush and slim hole upsets. This is indeed the case; API RP 7G lists these interchangeable and equivalent connections. Tool joints are identified by a series of 5 markings stenciled at the base of the pin connection: The first marking designates the company symbol. The second marking is a number from 1 to 12, indicating the month that the tool joint was welded. The third marking denotes the last two digits of the year in which the tool joint was welded (e.g., 06 ⇒ 2006). The fourth marking is the pipe mill code. The fifth marking is the pipe grade code, designated as follows: GradeSymbolN-80NEEC-75CX-95XG-105GS-135SV-150VHeavy WallDouble-stencilpipe grade code For example, the markings ZZ 5 09 I E at the base of the pin designate the company initials ZZ, and indicate that the tool joint was welded in May 2009 by Nippon Steel Corporation (designation I) on Grade E drill pipe. (adsbygoogle = window.adsbygoogle || []).push({}); Capacity and Displacement (adsbygoogle = window.adsbygoogle || []).push({}); Capacity is the amount of fluid that can be contained in a pipe or an annulus; it is generally expressed as volume per unit length (e.g., barrels per foot). Displacement is expressed either as the length of pipe required to displace a unit volume of fluid (e.g., feet per barrel), or the volume of fluid displaced by a unit length of pipe (e.g., barrels per foot). These quantities are fundamental to well planning and operations, particularly with respect to drilling fluids, well control and cementing. They can be determined using formulas or read from service company charts or tables. Capacity and Displacement Formulas The following formulas are adequate for quick calculations. But because they are based only on the pipe body diameters and do not account for upsets and tool joints, they are approximations only, and should be used with some caution. [latex]\textrm{Pipe Capacity} = \dfrac{\pi }{4}\cdot ID_{pipe} ^{2}[/latex] [latex]\textrm{Annular Capacity} = \dfrac{\pi }{4}\cdot \left (D_{hole}^2 - OD_{pipe}^2 \right )[/latex] [latex]\textrm{Displacement } = \dfrac{\pi }{4}\cdot \left (OD_{pipe}^2 - ID_{pipe}^2 \right )[/latex] where (adsbygoogle = window.adsbygoogle || []).push({}); IDpipe= inside diameter of pipe; ODpipe= outside diameter of pipe; Dhole= hole diameter (Note: in a cased hole, casing ID replaces hole diameter) With pipe diameter expressed in inches and capacity or displacement expressed in barrels per foot, the constant (π/4) is replaced by 0.0009714, or (1/1029). For example: The internal capacity of 4.5 inch, 16.60 lb/ft, plain-end drill pipe (inside diameter of 3.826 inches) is [latex]\quad 0.0009714\cdot 3.826^2 = 0.0142\, \tfrac{bbl}{ft}[/latex] The annular capacity in an 8.5-inch diameter hole would be [latex]\quad 0.0009714\cdot (8.5^2 - 4.5^2) = 0.0547\, \tfrac{bbl}{ft}[/latex] Its displacement is [latex]\quad 0.0009714\cdot (4.5^2 - 3.826^2) = 0.00545\, \tfrac{bbl}{ft}[/latex] Tables Tabulations of pipe capaciity and displacement are usually included in engineering data books published from oil field service companies and pipe manufacturers. These data books are available in hardcopy and digital formats. Some of the digital versions—notably Halliburton's eRedbook (a downloadable version of its classic Cementing Tables - include built-in calculators and other interactive applications. When using these tables, it is important to note the assumptions (for example, the type of upset or tool joint) under which the calculations were made. (adsbygoogle = window.adsbygoogle || []).push({}); Handling Guidelines (adsbygoogle = window.adsbygoogle || []).push({}); Mishandling, rough treatment and improper make-up can severely weaken oilfield tubulars. This is especially true for drill pipe, which is relatively thin and flexible compared to the rest of the drill string. Such weakening can lead to pipe or tool joint failures. To avoid such failures (and the fishing jobs that usually result), drilling personnel need to handle pipe with care. Although drilling engineers are not normally involved in handling tubulars, it is important that they be familiar with proper procedures and observe that they are being followed. Such attention to detail will, in the long run, prevent well problems. The guidelines in this section, taken from Rowe and Wilson (1981), provide a summary of good handling practices. Thread Protection Steel thread protectors should always be used when picking up, laying down, moving or storing oilfield tubulars. General guidelines are as follows: Before picking up drill pipe from the racks, remove the thread protectors, thoroughly clean all connections and inspect the connections for damage. If solvent or other liquid is used for cleaning, the connections must be dried before applying thread compound. This thread compound should be of a high grade, and API-recommended for tool joint use. Re-install the thread protectors before moving the pipe onto the catwalk. Do not remove them again until the joint is picked up and the connection is ready to be made. Pick-Up, Tripping and Lay-Down Pick-up, tripping and lay-down procedures can have punishing effects on drill pipe and increase the chances of failure. Here are some guidelines for minimizing these effects: Before picking up, tripping or laying down pipe, inspect all handling equipment for proper operation and signs of wear, including the elevators, the rotary table, the master bushing, the slip bowl, slips, tongs and pull lines. Worn elevator bores, shoulders or latches could result in dropping the drill string, while a damaged or worn rotary table, master bushing, bowl or slips could lead to crushing of the drill pipe tube. Stagger breaks on each trip so that each connection can be checked and thread compound reapplied every second or third trip. Exercise care when running in the hole - run in slowly enough to avoid sudden impact on ridges or shoulders, to avoid tagging bottom and to prevent high surging or swabbing pressures. Do not use the slips as a brake to stop the downward drill pipe movement when tripping in the hole. Do not allow the slips to "ride" the pipe when tripping out of the hole. Use backup tongs when breaking connections; do not depend on the weight of the drill string to keep the pipe from turning in the slips. Set the slips with the tool joint as near as practical to the rotary table— this minimizes the possibility of bending the pipe during make-up or breakout. When picking up, laying down or standing back pipe, make sure that the catwalk, V-door and derrick floor are clear of foreign objects that could cause impact damage, and that the pipe is cleaned of any damaging or corrosive fluids. (adsbygoogle = window.adsbygoogle || []).push({}); Connections Initial make-up is probably the most important factor affecting the life of tool joint connections. The following practices should be a part of make-up procedures: Pre-determine proper make-up torque, as specified for the particular connection, size, outside diameter and inside diameter. Use care when stabbing the pin connections into the box end, making sure that the pin does not strike the box shoulder or glance off the box threads. Make up connections slowly. High-speed kelly spinners or the spinning chain, when used on initial make-up, can cause galling of the threads. The driller should never jerk on the tong line to obtain proper make-up torque. Use a properly working, accurately calibrated torque gauge to measure the required line-pull as joints are made up to the required torque. This line pull is equal to the length of the tong arm (measured from the center of the tool joint, with the tongs in the set position at a 90° angle to the pull line) multiplied by the tong line pull. Inspection The IADC and the API have established detailed inspection guidelines for drill pipe and tool joints, which can be found in these standards: API RP 7G: Recommended Practice for Drill Stem Design and Operating Limits API RP 7G-2/ISO 10407-2: Recommended Practice for Drill Stem Element Inspection Drill string failures result primarily from fatigue. The API defines a fatigue failure as one "which originates as a result of repeated or fluctuating stresses having maximum values less than the tensile strength of the material." These stresses are products of the bending, torsion, vibration, tension and friction inherent in drilling operations, and are aggravated by corrosion, erosion, poor handling and other factors. Fatigue failures are progressive; they generally begin as small cracks, which propagate as continued stress is applied. Unfortunately, fatigue is hard to detect in its early stages, and there are no accepted procedures for determining the amount of accumulated fatigue damage or the remaining life of pipe. Accepted methods for inspecting the drill pipe tube involve: visual or magnetic particle inspection to locate cracks, pits and other surface marks; remaining wall thickness measurement, using either: pipe-wall micrometers; sonic pulse echo (resonance measurements); gamma ray devices, calibrated to within 2% accuracy; outside diameter measurement; cross-sectional area measurement, either by means of a direct-indicating instrument calibrated to within 2% accuracy, or by integrating wall thickness measurements taken at 1-inch intervals. Required API procedures for inspecting tool joints involve: measuring outside diameter. checking shoulders for galls, nicks, washes, fins or other evidence of wear. randomly checking 10% of the joints for manufacture markings and installation dates to determine if the tool joint has been reworked. Optional tool joint inspection procedures include: determining minimum acceptable shoulder width, as specified in API RP7G. measuring for box swell and/or pin stretch. examining thread profile for indications of overtorque, insufficient torque, lapped threads, galled threads and stretching; conducting a magnetic particle inspection if evidence of stretching or swelling is found. Fatigue failure can occur rapidly under certain conditions. In areas that experience a high incidence of washouts or pipe failures, drilling personnel must be particularly selective about what they run in the hole, even if it means discarding joints for which the only signs of fatigue might be a few gouges in the slip area. API 7G lists standards for classifying and identifying used drill pipe; Figure 1 shows where identification marks are applied. FIGURE 1 Automatic Pipe Handling (adsbygoogle = window.adsbygoogle || []).push({}); Automatic pipe racker systems provide a means of handling drill pipe by remote control. Operated from consoles on the rig floor (and, in some systems, from a derrick console) they use hydraulic, pneumatic or air power to latch and unlatch elevators, pull and set slips, make or break pipe connections, and lay down and pick up pipe. These systems are used primarily on floating drilling vessels, but are also available for use on platforms, jack-up rigs and land rigs. Automatic pipe handling systems can provide dramatic savings on trip time and manpower, but their greatest benefit is increased safety. Safety is an especially important consideration on floating drilling vessels, where rough weather and heavy seas frequently render manual methods of pipe handling not only impractical, but dangerous. Figure 2 (Horizontal handling system for conveying drill pipe and casing from the pipe racks to the rig floor), Figure 3 (Vertical handling system used to raise the pipe from horizontal, place it in vertical setbacks and finger boards for storage, and convey it to the center of the rig floor to be made up into the drill string) and Figure 4 (Iron roughneck used to make up the threaded pipe joints and torque them to precise specifications), taken aboard Japan's deep sea scientific drilling vessel D/V Chikyu, illustrate the main components of an automatic pipe handling system. FIGURE 2 FIGURE 3 FIGURE 4 (adsbygoogle = window.adsbygoogle || []).push({}); Fatigue and Drill String Failures (adsbygoogle = window.adsbygoogle || []).push({}); It is well known that metal is weaker under dynamic loading than under static conditions. Steel is capable of absorbing dynamic loading, or cycles of stress, for an infinite number of reversals if the stress is kept under a certain limit. This is illustrated in Figure 1—Example of an S-N curve showing stress versus number of cycles to produce failure. FIGURE 1 We can use as a simple illustration a nail (mild steel) that is bent back and forth until it breaks. The point at which the curve straightens out is called the endurance limit. If the stress does not exceed this limt, the material can undergo any number of cycles without experiencing failure. In this case, if the stress is kept below 27,000 psi the nail will not break regardless of how many times it is bent. At 30,000 psi the nail will break after 2,000,000 cycles. At 48,000 psi, which is the elastic limit, the nail will break immediately. These failures that occur under cyclic stress are called fatigue failures. Fatigue failure is progressive. It starts as a submicroscopic yielding of the atoms along the crystal slip planes. As the metal continues to move under alternating stress, heat is generated, lowering the cohesive strength of the constituents. This forms submicroscopic cracks which progressively unite until the resulting crack becomes visible. The direction of the crack is normal (90 degrees) to the stress— drill pipe failures are thus circumferential. Some of the properties of steel that determine its endurance limt include chemical composition, microstructure, surface finish, and tensile properties. As a very rough approximation, the fatigue strength of drill pipe is about one half of its tensile strength. In addition, the presence of notches and corrosion have a great effect on the fatigue strength. Drill pipe is subjected to cyclic stresses in tension, compression, torsion and bending. Tension and bending (alternate tension and compression of the same pipe wall) are the most critical of these stresses. The magnitude of any stress can be compounded by the effect of vibration. (adsbygoogle = window.adsbygoogle || []).push({}); Pure fatigue failures in straight hole drilling—exclusive of dog-legged or deviated holes, or where failures are associated with notches and corrosion—are becoming less frequent. As is discussed in the IPIMS subtopic Drill Collars, this is due to the general practice of using sufficient drill collar weight (accounting for buoyancy and hole inclination) so that the drill string is in tension down through the top two or three drill collars. Today the major factor in fatigue failures is the cyclic bending when pipe is rotated in a hole having a change in direction, or dog-leg. This occurs in straight hole drilling as well as in directional drilling. Failure can occur even when proper drill collar weight is maintained, and there is no permanent set in the drill pipe. When pipe is deflected and rotated, it goes through cycles of stress from tension to compression on each side of the pipe with each rotation. It might be noted that drill pipe rotating at 100 rpm makes 144,000 revolutions per day if left on bottom continually. Hence in just 7 days there could be more than a million stress cycles on the pipe when rotating under conditions creating variable stress. The portion of the drill string that is most subject to bending is the drill pipe, just above the drill collars. The maximum stress on the drill pipe occurs in the relatively thin pipe wall, from the run-out point of the upset to approximately 20 inches from the tool joint. This change of cross section in the tool joint acts as a vise and becomes the fulcrum of the bending force. If the pipe could bend uniformly throughout its length, stress would be lower and cycles of stress to failure would be higher. The amount of drill pipe fatigue damage depends upon: The tensile load in the pipe at the dog-leg. The severity of the dog-leg. The number cycles in the dog-leg of each portion of the pipe. The dimensions and properties of the pipe. Methods are available for estimating the cumulative fatigue on joints of pipe that have been rotated through severe doglegs. The method portrayed in Figure 2 (Fatigue damage in gradual doglegs in a non-corrosive environment. Simple device to be used as a guide in analyzing joints suspected of suffering fatigue damage. FIGURE 2 (adsbygoogle = window.adsbygoogle || []).push({}); For example, consider a string of 3.5-inch diameter drill pipe under the following conditions: Rotary speed = 100 RPM Rate of penetration = 100 ft/hr Dog-leg severity = 10 degrees per 100 ft Length of drill pipe below dog-leg = 6000 ft Non-corrosive environment Based on Figure 2, the tension on the drill pipe would be 70,000 lbf, and the dog-leg would expend about 35 percent of the life of the drill pipe joint. Note that such damage is permanent even though the stress is relieved and/or the joint passes through the dog-leg. Similar repetitive stresses on the joint will eventually cause failure. Thus, if the joint passes through this or a similar dog-leg with the same rotary speed and penetration rate three times it will fail. In the same regard, drill pipe may be damaged on one hole even though it does not fail. If it is placed near the top of the string on the same or next hole, it may or may not be able to withstand the very nominal bending stresses encountered. Thus, failures can occur later and far from the position in the string where the trouble started, or in subsequent wells. A correction formula to use for other penetration rates and rotary speed is: [latex]\textrm{Life Expended} =\left (\textrm{life exoended from API charts } \right ) \cdot \left (\dfrac{\textrm{Actual RPM}}{100} \right ) \cdot \left (\dfrac{10}{\textrm{Actual}}\ \frac{\textrm{ft}}{\textrm{hr}} \right )[/latex] In other words, three times the rotary speed at 1/3 the penetration rate will give the same effect. If dog-legs of sufficient magnitude are known or suspected, it is good practice to string-ream the dog-leg area. This reduces the severity of the hole angle change. (adsbygoogle = window.adsbygoogle || []).push({}); Heavy Wall Drill Pipe https://youtu.be/j06fdLS2cKQ (adsbygoogle = window.adsbygoogle || []).push({}); Heavy wall drill pipe (Figure 1) is an intermediate drill string member — heavier, stronger and stiffer than regular drill pipe, but at the same time more flexible than drill collars. FIGURE 1 Because it has the same external dimensions as regular drill pipe, it is much easier to handle than drill collars. Figure 2 illustrates some of its important features. FIGURE 2 The most important drill string application for heavy wall drill pipe is in the area above the topmost drill collars where drill pipe fatigue failure is most likely to occur. To reduce fatigue failures in this area of the borehole, 18 to 21 joints of heavy wall drill pipe may be run above the drill collars. This provides a gradual change in stiffness between drill collars and drill pipe. Also, the ability of the heavy wall drill pipe to bend (unlike drill collars) serves to relieve high stresses at the connections. To prevent too great a change in stiffness between the drill collars and the heavy wall drill pipe, the guidelines below can be used. (adsbygoogle = window.adsbygoogle || []).push({}); Heavy Wall Drill Pipe OD (inches )Maximum Drill Collar OD (inches)3.506.004.006.504.507.255.008.25Table 1. Sizing guidelines for heavy wall drill pipe and drill collars Heavy wall drill pipe was first used in directional drilling, which generally requires flexibility in the drill string. It is now widely used in vertical and horizontal drilling as well. With less wall contact than would be experienced with drill collars, its usage reduces torque and wall-sticking tendencies. Its smaller degree of wall contact, together with its greater stiffness relative to regular drill pipe, results in increased stability and better directional control. Heavy wall drill pipe is also useful in reducing hook loads, making it ideal for smaller rigs drilling deeper holes. In certain special applications (most notably horizontal drilling) heavy wall drill pipe may be run in compression. It is important to keep in mind, however, that a joint of heavy wall drill pipe is not as strong as a drill collar, and that it is still susceptible to buckling and fatigue failure. In a vertical hole, heavy wall drill pipe must be maintained in tension. (adsbygoogle = window.adsbygoogle || []).push({}); Exercises (adsbygoogle = window.adsbygoogle || []).push({}); 1. Drill pipe strength is measured in terms of (choose one) Torsional yield strength Tensile yield strength Collapse resistance Internal yield (a) and (b) only (a) and (c) only (a), (b), (c) and (d) Solution Drill pipe strength is measured in terms of torsional yield, tensile yield, collapse resistance and internal yield. 2. You are designing a drill string for a new well, and have the option of using one of the following types of drill pipe: 4 1/2′′ , 16.60 lb/ft , Grade E, Internal-External Upset, with NC46 (XH) tool joint4 1/2′′ , 16.60 lb/ft , Grade 95, Internal-External Upset, with NC46 (XH) tool jointThe drill string is to be used for a vertical well with a projected depth of 15,000 ft. The length of the bottomhole assembly will be 1270 ft, with a weight of 125,000 lb. Based on tensile yield strength only, which grade of drill pipe should you use? As a safety factor, assume that there is no buoyancy (that is, use the weight of the string in air). Solution Tensile stress will be a maximum at the top joint. Step 1: Calculate the total weight of the drill string in air. Total weight = (weight of bottomhole assembly) + (weight of drill pipe) Total weight =(weight of bottomhole assembly)+(weight of drill pipe) Total weight =125,000+[16.60⋅(15,000−1,270)]=352,918 lbs Step 2: Compare the total drill string weight to the tensile yield strength of the drill pipe. Cross-sectional area of 4 1/2; drill pipe body = [latex]\dfrac{\pi }{4}\cdot \left ( 4.5^2-3.826^2 \right )=4.407\ in^2[/latex] Grade E: Minimum tensile yield = 75,000 psi ; joint yield strength = 4.407⋅75000=330,558 lb; less than total weight of string Grade 95: Minimum tensile yield = 95,000 psi ; joint yield strength = 4.407⋅95000=418,707 lb; greater then total weight of string On the basis of drill pipe body alone, we must use Grade 95 pipe. 3. You are inspecting a string of drill pipe that has just been delivered to your rig, and notice a series of five markings stencilled at the base of the pin on a tool joint. Explain what each marking means. Solution First marking: Company symbol. Second and third markings: Month and year, respectively, that the tool joint was welded. Fourth marking: Pipe mill code Fifth marking: Pipe grade code 4. Determine the internal capacity of the following drill string: Drill string: 7,800 ft of 5", 19.50 lb/ft drill pipe (capacity = .01776 BBL/ft) 900 ft of 8" OD, 150 lb/ft drill collars (capacity = .00735 BBL/ft) Solution Pipe capacity=(7800′⋅0.01776)+(900′⋅0.00735)=145.14 BBL 5. You notice some joints of drill pipe on the pipe racks that have red bands painted on the pipe body. Should these joints be picked up in the drill string? Solution The red bands indicate that these joints are scrap. Do not pick them up, but have them removed from the racks. Assessment (adsbygoogle = window.adsbygoogle || []).push({}); 1. The length of Range 2 drill pipe, which is the one most commonly used, is: A .18-22 ftB .27-30 ftC .30-37 ftD .38-45 ft 2. Collapse resistance is: A .Resistance to twisting forceB .Resistance to axial tensionC .Resistance to external pressureD .Resistance to internal pressure 3. Which of these statements about drill pipe tool joints is FALSE? A .Tool joints are fabricated separately from the drill pipe tube and then welded on at the upsets.B .A Full Hole (FH) tool joint corresponds to an API NC-40 numbered connection.C .Tool joint specifications usually include information on recommended makeup torque.D .Five threads per inch is the standard for fabricating tool joints. 4. Of the five markings that identify tool joints the third one: A .Designates the pipe mill codeB .Designates the month in which it was weldedC .Designates the company symbolD .Designates the pipe grade codeE .Designates the year in which it was welded 5. What would be the annular capacity, opposite the pipe body, for a 9 7/8-inch hole containing 5-inch, 19.50 lb/ft drill pipe? A .0.0242 bbl/ftB .0.0586 bbl/ftC .0.0704 bbl/ftD .0.0897 bbl/ft 6. Which of these is NOT a recommended guideline for proper drill pipe handling? A .After inspecting pipe on the racks and applying thread compound, re-install the thread protectors before moving the pipe onto the catwalk.B .When breaking connections, use the weight of the drill string as a back-up to keep the pipe from turning in the rotary table.C .Make up connections slowly to prevent galling of threads. 7. “Required” API procedures for inspecting tool joints include: A .Outside diameter measurementB .Box swell measurementC .Magnetic particle inspectionD .A through CE .B, and C 8. In a vertical or "straight" hole, the portion of the drill string that is most subject to bending is __________________. A .just below the uppermost drill collarB .several stands below the surface, in the drill pipe bodyC .in the pipe body, roughly halfway between the rotary table and the bottomhole assemblyD .in the tool joint, roughly halfway between the rotary table and the bottomhole assemblyE .in the tool joint nearest to the drill collarsF .in the drill pipe body just above the tool joint nearest to the drill collars. 9. What is the endurance limit of a material? A .The stress that causes immediate failure of a material.B .The stress at which cracks in the material become visible.C .The stress at or below which the material will not fail, regardless of how many stress cycles it undergoes. Recommended for You (adsbygoogle = window.adsbygoogle || []).push({}); Directional Drilling Overview Drill String and Bit Considerations in Deviated Wells Drill String Overview What is a Kelly in drilling? (adsbygoogle = window.adsbygoogle || []).push({});