Thịnh drilling engineering fundamentals, ch 1, 2, 3, 4, 5, 7, 8 10

Drilling Engineering Fundamentals Associate Professor Jorge H.B Sampaio Jr., PhD Curtin University of Technology Department of Petroleum Engineering j.sampaio@curtin.edu.au April 3, 2007 Contents Introduction 1–1 1.1 Objectives 1–1 1.2 General 1–1 1.3 Drilling Rig Types 1–3 1.4 Personnel at Rig Site 1–5 1.5 Miscellaneous 1–7 Rotary Drilling System 2–1 2.1 Power System 2–5 2.1.1 Energy, Work, and Efficiency 2–6 2.2 Hoisting System 2–8 2.2.1 The Derrick 2–10 2.2.2 The Drawworks 2–11 2.2.3 The Block & Tackle 2–12 2.2.4 Load Applied to the Derrick 2–16 2.3 Drilling Fluid Circulation System 2–18 2.3.1 Mud Pumps 2–20 2.3.2 Solids Control Equipment 2–25 2.3.3 Treatment and Mixing Equipment 2–30 2.4 The Rotary System 2–33 2.4.1 Swivel 2–33 2.4.2 Kelly, Kelly Valves, and Kelly Saver Sub 2–33 2.4.3 Rotary Table and Components 2–36 2.5 Well Control System 2–38 2.6 Well Monitoring System 2–43 Drillstring Tubulars and Equipment i 3–1 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 3.1 Drill Pipes 3–1 3.1.1 Drill Pipe Elevator 3–5 3.2 Drill Collars 3–5 3.3 Heavy Wall Drill Pipes 3–6 3.4 Special Tools 3–7 3.4.1 Stabilizers 3–7 3.4.2 Reamers 3–9 3.4.3 Hole–openers 3–9 3.5 Connections Make–up and Break–out 3–10 3.5.1 Maximum Height of Tool Joint Shoulders 3–11 3.5.2 Make–up Torque 3–13 3.6 Drill Bit 3–13 3.7 Other Drillstring Equipment 3–14 3.7.1 Top Drive 3–14 3.7.2 Bottom Hole Motors 3–15 Introduction to Hydraulics 4–1 4.1 Hydrostatic Pressure 4–1 4.1.1 Hydrostatic Pressure for Incompressible Fluids 4–2 4.1.2 Hydrostatic Pressure for Compressible Fluids 4–4 4.2 Buoyancy 4–7 Drillstring Design 5–1 5.1 Length of Drill Collars – Neutral Point Calculation 5–1 5.2 Design for Tensile Force, Torque, Burst, and Collapse 5–6 5.2.1 Maximum Tensile Force 5–6 5.2.2 Maximum Torque 5–9 5.2.3 Internal (Burst) and External (Collapse) Pressures 5–10 5.2.4 Drillstring Elongation 5–12 Drilling Hydraulics 6–1 6.1 Mass and Energy Balance 6–1 6.1.1 Mass Conservation 6.1.2 Energy Conservation 6–2 6–3 6.2 Flow Through Bit Nozzles 6–6 ii Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 6.2.1 Pressure Drop Across the Bit 6–6 6.2.2 Hydraulic Power Across the Bit 6–8 6.2.3 Impact Force of the Jets 6–8 6.3 Required Hydraulic Power 6–10 6.4 Bit Hydraulics Optimization 6–11 6.4.1 Nozzle Size Selection Criteria 6–13 6.4.2 Graphical Analysis 6–16 Introduction to Drilling Fluids 7–1 7.1 Functions of Drilling Fluids 7–1 7.2 Types of Drilling Fluid 7–2 7.2.1 Water–Base Fluids 7–3 7.2.2 Oil–Base Muds 7–6 7.2.3 Synthetic Fluids 7–7 7.2.4 Aerated Fluids 7–7 7.3 Laboratory Tests 7–7 7.3.1 Water–Base Mud Tests 7–7 7.3.2 Oil-Base Mud Testing 7–12 7.4 Fluid Density and Viscosity Calculations 7–13 7.4.1 Density Calculations 7–14 7.4.2 Density Treatment 7–15 7.4.3 Initial Viscosity Treatment 7–19 Rheology and Rheometry 8–1 8.1 Rheological Classification of Fluids 8–1 8.2 Rheometry 8–4 8.2.1 Viscosity of Newtonian Fluids 8–5 8.2.2 Parameters of Bingham–Plastic Model Fluids 8–5 8.2.3 Parameters of Power–Law Model Fluids 8–5 8.2.4 Gel Strength 8–6 Flow in Pipes and Annuli 9–1 9.1 Laminar Flow in Pipes and Annuli 9–1 9.1.1 Equilibrium Equations 9–2 9.1.2 Continuity Equations 9–3 iii Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 9.1.3 Newtonian Flow in Pipes – Poiseuille’s Equation 9–5 9.1.4 Newtonian Flow in Concentric Annuli – Lamb’s Equation 9–6 9.1.5 Slot Approximation for Newtonian Fluids 9–9 9.1.6 Pressure Drop Gradient for Non–Newtonian Fluids 9–10 9.2 Turbulent Flow in Pipes and Annuli 9–12 9.2.1 Turbulent Flow of Newtonian Fluids in Pipes 9–12 9.2.2 Criterion for Laminar – Transition – Turbulent Flow 9–19 9.2.3 Other Geometries – Turbulent Flow in Annuli (Newtonian) 9–20 9.2.4 Turbulent Flow for Non–Newtonian Fluids 9–22 10 Drilling Bits 10–1 10.1 Drill Bit Types 10–1 10.1.1 Roller Cone Bit 10–2 10.1.2 Air Drilling Bits 10–8 10.1.3 Fixed Cutter Bits (Drag Bits) 10–8 10.2 Bit Classification 10–15 10.2.1 PDC Bit Classification System 10–18 10.3 Drill Bit Selection and Evaluation 10–20 10.3.1 Tooth Wear 10–21 10.3.2 Bearing Wear 10–21 10.3.3 Gage Wear 10–22 10.4 Factors that Affect the Rate Of Penetration 10–22 10.4.1 Bit Type 10–22 10.4.2 Formation Characteristics 10–22 10.4.3 Drilling Fluid Properties 10–23 10.4.4 Operating Conditions 10–25 A Drill Pipe Dimensions (as in API RP7C) iv A–1 List of Figures 1.1 Rig Classification 1–3 2.1 Typical rig components 2–1 2.2 A simplified drillstring 2–3 2.3 Making a connection 2–4 2.4 Rig crew setting the slips 2–4 2.5 Removing one stand of drillstring 2–5 2.6 Typical hoisting system 2–9 2.7 Stand of doubles along the mast 2–10 2.8 Onshore rig drawworks 2–11 2.9 Brake belts and magnification linkage 2–11 2.10 Drawworks schematics 2–12 2.11 Forces acting in the block–tackle 2–13 2.12 Derrick floor plan 2–17 2.13 A swivel 2–19 2.14 Rig circulation system 2–20 2.15 Duplex pumps 2–22 2.16 Triplex pumps 2–22 2.17 Surge dampener 2–24 2.18 Solids control system 2–25 2.19 Shale shaker configurations 2–26 2.20 A two–screen shale shaker 2–26 2.21 A vacuum chamber degasser 2–27 2.22 Flow path in a hydrocyclone 2–28 2.23 Solid control equipment 2–28 2.24 Particle size classification 2–29 2.25 Internal view of a centrifuge 2–30 v Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 2.26 Mud cleaner 2–31 2.27 Mud agitator 2–31 2.28 Mud gun 2–32 2.29 Mud hopper 2–32 2.30 Cut views of a swivel 2–34 2.31 A square kelly and a hexagonal kelly 2–35 2.32 A kelly valve 2–35 2.33 Kelly bushings 2–36 2.34 Master bushings ([a] and [b]), and casing bushing (c) 2–36 2.35 Kelly bushing and master bushing 2–37 2.36 Drillpipe slip (detail when set in the master bushing) 2–37 2.37 DC slips, safety collar, and casing slips 2–38 2.38 A rotary table 2–38 2.39 BOP stacks 2–39 2.40 Annular BOP’s (a and b) and an inside BOP (c) 2–40 2.41 BOP: (a) blind and pipe rams, (b) shear rams 2–41 2.42 BOP accumulators and control panels 2–42 2.43 Choke manifold 2–42 2.44 Weight indicator (a) and a deadline anchor (b) 2–44 2.45 Drilling control console 2–44 3.1 Typical rotary drillstring 3–2 3.2 Typical tool joint designs (A) Internal upset DP with full–hole shrink–grip TJ, (B) External upset DP with internal–flush shrink– grip TJ, (C) External upset DP with flash–weld unitized TJ, (D) External–internal upset DP with Hydrill™–pressure welded TJ 3–3 3.3 A DP elevator and the links to the hook body 3–5 3.4 A spiraled and a slick drill collars 3–6 3.5 Spiraled DC cross–section 3–6 3.6 A DC elevator 3–6 3.8 Heavy wall drill pipes 3–7 3.9 Some Stabilizers: (a) integral, (b) interchangeable, (c) non–rotating, (d) replaceable 3–8 3.10 A roller reamer 3–9 3.11 A fixed hole–opener 3–9 vi Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 3.12 Manual tongs 3–10 3.13 Tongs in position to make–up a connection 3–11 3.14 A spinner 3–12 3.15 Tongs position during make–up 3–12 3.16 3–12 3.17 An electrical top drive 3–14 3.18 A bottom hole turbine 3–15 3.19 A bottom hole PDM 3–15 4.1 Stress state about a point in a fluid 4–1 4.2 Real gas deviation factor 4–5 4.3 Drillstring schematics for Example 12 4–9 5.1 Assumption – pressure contributes to buckling 5–2 5.2 Assumption – pressure does not contribute to buckling 5–4 6.1 Mass balance 6–2 6.2 Schematic of a circulation system 6–5 6.3 Longitudinal cut of bit nozzles (Courtesy SPE) 6–6 6.4 Pressure drop across the bit 6–7 6.5 Jet impact force 6–9 6.6 Line of maximum hydraulic power 6–16 6.7 Additional hydraulic constraints 6–17 6.8 Ideal surface operational parameters 6–18 6.9 Path of optimum hydraulics 6–19 6.10 Frictional pressure drop lines 6–20 6.11 Graph for Example 27 6–21 7.1 A mud balance 7–8 7.2 A Marsh funnel 7–8 7.3 A rotational viscometer (rheometer) 7–9 7.4 A API filter press 7–9 7.5 A HTHP filter press 7–9 7.6 Sand content sieve 7–10 7.7 Retort 7–10 7.8 Methyl blue capacity test kit 7–11 vii Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 7.9 A pH meter 7–11 7.10 A titration kit 7–12 7.11 A permeameter kit 7–12 7.12 An aniline point kit 7–13 7.13 Electrical stability tester 7–13 7.14 Clay performance for viscosity 7–21 8.1 Typical graph of Newtonian fluids 8–2 8.2 Typical graph of Bingham-plastic fluids 8–3 8.3 Typical graphs of power–law fluids 8–3 8.4 Arrangement of a rotational viscometer 8–4 9.1 Velocity profiles of laminar flow 9–3 9.2 Velocity profile of laminar flow in a slot 9–4 9.3 Slot approximation of an annulus 9–9 9.4 Fluid particle flowing in a pipe 9–14 9.5 Stanton chart 9–15 9.6 Selection of the correct pressure drop value 9–19 10.1 Typical roller cone bits 10–2 10.2 Cut view of a roller cone bits 10–3 10.3 Cut view of a non–sealed bearing bit 10–4 10.4 A sealed bearing bit 10–5 10.5 Cut view of a roller bearing cone 10–5 10.6 Cut view of a journal bearing cone 10–6 10.7 Geometry of bit cones 10–7 10.8 Cone offsets 10–8 10.9 Air drilling bits 10–9 10.10Steel blade drag bits 10–10 10.11A diamond bit 10–10 10.12Schematic and nomenclature of diamond bit 10–11 10.13PDC bits 10–13 10.14Schematic and nomenclature of a PDC bit 10–14 10.15Nozzles in a PDC bit 10–14 10.16Back rake and side rake angles in PDC bits 10–14 viii Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals 10.17IADC roller cone bit classification chart 10–16 10.18Tooth wear diagram for milled tooth bits 10–21 10.19Correlation between rock strength and threshold WOB 10–23 10.20Variation of ROP with different fluid properties 10–24 10.21Effect of differential pressure in the ROP 10–25 10.22Exponential relationship between of differential pressure and ROP.10–26 10.23Effect of WOB (a) and rotary speed (b) in the ROP 10–26 ix Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals course design of most natural diamond and many TSP bits Such designs are further described as having either radial flow, crossflow (feeder/collector), or other hydraulics Thus, the letters R (radial flow), X (crossflow), or O (other) are used as the hydraulic design code for such bits Cutter Size and Placement Density The numbers through and in the 4th character of the fixed cutter classification code refer to the cutter size and placement density on the bit A x matrix of cutter sizes and placement densities defines numeric codes (see Table 10.4 Table 10.4: Range for IADC cutter size and density Density light medium heavy large medium small The placement density varies from light to medium to heavy from left to right in the matrix The cutter size varies from large to medium to small from top to bottom The ultimate combination of small cutters set in a high density pattern is the impregnated bit, designated by the number 10.3 Drill Bit Selection and Evaluation Since a well is drilled only once and each well penetrated the formations at different locations with different drilling parameters, a selection of a “best bit” can not be performed The next best way to find an “optimum bit” is to compare bit performances of drilling bits when they were run under similar conditions Then a cost–per–foot value of each bit application can be calculated Along with this criteria, the individual bit wear are evaluated This knowledge is applied to the well to be drilled (length, inclination, drillability, abrasiveness, etc of the different sections) In practice, when the well is planned, bits that have been used previously in this area (by this drilling team) are evaluated according to their applicability Sometimes when a bit manufacturer has developed a new bit, it is introduced to the industry with an expected minimum performance Thus, when such a new bit is applied and the proposed performance is met (usually better than ones of already applied bits), the operator has increased the pool of possible bits to use for future wells In case the performance proposed by the manufacturer is not met, agreements that the bit is given at reduced cost to the operator are common Another way of bit evaluation is the determination of the specific energy CHAPTER 10 Drilling Bits Page 10–20 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Figure 10.18: Tooth wear diagram for milled tooth bits using Equation (10.2) e= 2πN T W OB + , Ah Ah ROP (10.2) where W OB is the weight applied to the bit, Ah is the cross–sectional area of the hole, N is the rotary speed, T is the torque at the bit, and ROP is the rate of penetration Here the cutting–performance of various bits are compared to each other For this, the mechanical energy of the bit is related to the drilled rock volume It should be noted that a bit selection considering the specific energy may not lead to the finding of the most economic bit In all practical cases, to evaluate previously applied bits, the so called bit records are studied These bit records include all available information (bit size, type, manufacturer, nozzles used, rotation time, applied WOB, applied RPM, etc) about the bits applied within drilled wells 10.3.1 Tooth Wear With tooth wear, the reduction of tooth height is graded after a bit was run The grading is reported in nearest eighth, thus a bit whose teeth are worn out to half of its original height, is reported as T–4 Normally the tooth wear of a bit is not even distributed over the bit, some teeth are worn more than others, some are broken out Broken teeth are generally remarked as “BT” The reported wear is an average one based on the most severely worn teeth Reporting of the tooth wear is possible when the teeth are measured before and after the bit was run In general, tooth wear has no direct relationship with the drilling rate realizable For insert bits, tooth wear occurs, due to the hardness of the teeth, as breaking or losing of them Thus a T-4 graded insert bit may have half of its teeth broken or lost A diagram of tooth wear for milled bits is shown in Figure 10.18 10.3.2 Bearing Wear Evaluation of bearing wear in the field is difficult since the bit would need to be disassembled for inspection Thus it is mainly determined if the bearings are intact or failed Failed bearings is the situation that the cones are stuck (no rotation possible), or that they are worn out and the bearings are exposed The classification is similar to the tooth wear, using a B instead of T Thus a bit which bearings are worn to is marked as B–7 CHAPTER 10 Drilling Bits Page 10–21 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Often the bearing wear is reported based on the total bit running hours Thus, when a bit is expected to have a rotation time of 40 hours and was rotating on bottom for 10 hours, the bearing wear is reported as B-2 10.3.3 Gage Wear When the gauge diameter of a bit is worn, the drilled hole will be undergage (and tapered) with may lead to damage of the next bit and stuck pipe Measurement of the gauge wear is performed with the help of a calliper and a ruler The loss of diameter in eighth of inches is reported, denoting with the letter “O” for “out of gage” In this way, a bit which diameter is reduced by 0.5 in is reported as G–O–4 When the bit is in gauge, it is reported using the letter “I” In addition to the wear gradings listed above, the bit record commonly includes a column of comments Here the bit conditions are commonly remarked 10.4 Factors that Affect the Rate Of Penetration Although throughout the text various aspects that influence the ROP are mentioned whenever appropriate, the following considerations are often applied to determine the recommended drilling parameters 10.4.1 Bit Type The type of bit used to drill a certain formation has a large impact on the achieved penetration rate Roller cutting bits with long teeth exhibit commonly the highest penetration rates but they are only applicable at soft formations At hard formations where PDC bits dominate, the realized ROP is mainly a function of size and amount of cutters, along with an optimum combination of drilling parameters 10.4.2 Formation Characteristics The most important formation properties that determine the penetration rate are the elastic limit and the ultimate rock strength The strength of a formation is usually estimated using the Mohr failure criteria   When drilling is initiated, a threshold force or bit weight W has to be db t overcome This threshold force can be found when plotting drilling rates as a function of bit weight per diameter and then extrapolated to zero drilling rate A correlation between threshold and shear strength is shown in Figure 10.19 CHAPTER 10 Drilling Bits Page 10–22 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Figure 10.19: Correlation between rock strength and threshold WOB Another formation property that has a large influence to the realized ROP is the permeability In rocks with high permeability, the drilling mud filtrates into the rock ahead of the bottom of the hole and thus reduces the differential pressure Other rock properties like its abrasiveness and gummy clay minerals content contribute indirectly to the ROP by influencing the drilling bit (wear, dulling, etc) 10.4.3 Drilling Fluid Properties Among the various drilling fluid properties, the following are identified as influencing the penetration rate: [(a)] drilling fluid density, rheological flow properties, filtration characteristics, solids content and distribution, CHAPTER 10 Drilling Bits Page 10–23 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Figure 10.20: Variation of ROP with different fluid properties chemical composition Penetration rate in general decreases with increasing fluid density, viscosity, and solids content, and increases with increasing filtration rate This latter is mainly caused by the reduction of the differential pressure in the formation right below the bottom of the hole The drilling fluid viscosity controls the frictional pressure losses along the drillstring and thus reducing the available hydraulic energy at the bit Solids particles with size less than µm (colloid size) influence the ROP dramatically since they tend to plug off the porous of the rock, reducing the filtration below the bit The effects of these various parameters are loosely shown in Figure 10.20 The penetration rate is largely dependent on the differential pressure as seen in Figure 10.21 The effective differential pressure at the bottom has several implications in reducing the ROP The first is the chip hold–down effect The second is the increase of the confining pressure, which increases the strength of the rock If the rate of penetration versus pressure differential is plotted in a semi– log paper, a reasonable linear relationship can be obtained, as seen in Figure 10.22 An expression for the relationship can then be written as: log R = −m (pbh − pf ) , R0 where R is the rate of penetration at a particular overbalance, R0 is the rate of penetration for zero overbalance, m is the slope or the regressed line, pbh is the CHAPTER 10 Drilling Bits Page 10–24 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Figure 10.21: Effect of differential pressure in the ROP bottom hole pressure, and pf is the formation pore pressure at the bottom hole depth 10.4.4 Operating Conditions The effects of changes in the operating conditions, namely WOB and rotary speed, are shown in Figure 10.23 Ideally, the ROP should increase linearly with the WOB (for a fixed rotary speed), as shown in the segment a–b–c in the graph However, field tests show that above a given value the response departs from the linear behavior, and an increase in WOB does not correspond to the expected increase in ROP, as in the segment c–d In situations as in the segment d–e, the rate of penetration may even reduce This behavior is called “floundering” Two factors contribute to the floundering behavior One is the reduction of hole cleaning capacity due to the increase of ROP (assumed the hydraulics is kept constant) The second is the complete imbedding of the cutters (teeth or inserts) into the formation It is important, therefore to find the onset of the floundering region Drillers conduct a variety of tests to optimize performance The most common is the drill rate test, which consists of simply experimenting with various WOB and CHAPTER 10 Drilling Bits Page 10–25 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Figure 10.22: Exponential relationship between of differential pressure and ROP (a) (b) Figure 10.23: Effect of WOB (a) and rotary speed (b) in the ROP RPM settings and observing the results The parameters are then used that resulted in the highest ROP In some sense, all optimization schemes use a similar comparative process That is, they seek to identify the parameters that yield the best results relative to other settings Another scheme is the drilloff In the drilloff test, the driller applies a high WOB and locks the brake to prevent the top of the string from advancing while continuing to circulate and rotate the string As the bit drilled ahead, the string elongated and the WOB declined ROP was calculated from the change in the rate of drill string elongation as the weight declined The point at which the ROP stops responding linearly with increasing WOB is defined as the flounder point This is taken to be the optimum WOB This process has enhanced performance, but does not provide an objective assessment of the true potential drill rate, only the flounder point of the current system CHAPTER 10 Drilling Bits Page 10–26 Curtin University of Technology Department of Petroleum Engineering 10.4.4.1 Master of Petroleum Well Engineering Drilling Engineering Fundamentals Bit Wear As the bit is worn during drilling, the penetration rate decreases This reduction of ROP is generally less severe for insert bits as for milled tooth bits 10.4.4.2 Bit Hydraulics Practice has shown that effective bit hydraulics can improve the penetration rate dramatically The enhanced jetting action promotes a better cleaning of the teeth as well as the bottom of the hole To improve the cleaning capacity of the bit extended nozzles are often used where the discharging nozzle ends are closer to the hole bottom Extended nozzles usually requires the use of a 4th central nozzle, to guarantee a suitable cleaning of the cones, particularly in “gummy” formations As discussed in well hydraulics, maximum hydraulic horsepower and maximum jet impact force are the most used criteria to optimize hydraulics When a low WOB is applied and drilling rates are low, the required hydraulics for efficient hole cleaning is small When the WOB is increased and the well is drilled faster, efficient hydraulic programs have to be followed to realize the higher penetration rates CHAPTER 10 Drilling Bits Page 10–27 Curtin University of Technology Department of Petroleum Engineering CHAPTER Drilling Bits Master of Petroleum Well Engineering Drilling Engineering Fundamentals Page –28 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Appendix A Drill Pipe Dimensions (as in API RP7C) CHAPTER A Drill Pipe Dimensions Page A–1 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Table A.1: New Drill Pipe Dimensional Data (1) Size OD in D (2) Nominal Weight Threads and Couplings, lb/ft 4.85 6.65 (3) (4) (5) ID in d 1.995 1.815 (6) Section Area Body of Pipe sq in A 1.3042 1.8429 (7) Polar Sectional Modulus cu in Z 1.321 1.733 Plain end Weight lb/ft 4.43 6.26 Wall Thickness in 0.190 0.280 78 6.85 10.40 6.16 9.72 0.217 0.362 2.441 2.151 1.8120 2.8579 2.241 3.204 12 9.50 13.30 15.50 8.81 12.31 14.63 0.254 0.368 0.449 2.992 2.764 2.602 2.5902 3.6209 4.3037 3.923 5.144 5.847 11.85 14.00 15.70 10.46 12.93 14.69 0.262 0.330 0.380 3.476 3.340 3.240 3.0767 3.8048 4.3216 5.400 6.458 7.157 12 13.75 16.60 20.00 22.82 12.24 14.98 18.69 21.36 0.271 0.337 0.430 0.500 3.958 3.826 3.640 3.500 3.6004 4.4074 5.4981 6.2832 7.184 8.543 10.232 11.345 16.25 19.50 25.60 14.87 17.93 24.03 0.296 0.362 0.500 4.408 4.276 4.000 4.3743 5.2746 7.0686 9.718 11.415 14.491 12 19.20 21.90 24.70 16.87 19.81 22.54 0.304 0.361 0.415 4.892 4.778 4.670 4.9624 5.8282 6.6296 12.221 14.062 15.688 58 25.20 27.70 22.19 24.22 0.330 0.362 5.965 5.901 6.5262 7.1227 19.572 21.156 38 CHAPTER A Drill Pipe Dimensions Page A–2 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Table A.2: New Drill Pipe Torsional and Tensile Data Courtesy API CHAPTER A Drill Pipe Dimensions Page A–3 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Table A.3: New Drill Pipe Collapse and Internal Pressure Data Courtesy API CHAPTER A Drill Pipe Dimensions Page A–4 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Table A.4: Premium Drill Pipe Torsional and Tensile Data Courtesy API CHAPTER A Drill Pipe Dimensions Page A–5 Curtin University of Technology Department of Petroleum Engineering Master of Petroleum Well Engineering Drilling Engineering Fundamentals Table A.5: Premium Drill Pipe Collapse and Internal Pressure Data Courtesy API CHAPTER A Drill Pipe Dimensions Page A–6